IR 05000247/2007007

IR 05000247-2007-007, on Dates 1/8/2007 - 2/15/2007, Indian Point Nuclear Generating Station, Unit 2; Component Design Bases Inspection

ML070890270
Person / Time
Site:	Indian Point
Issue date:	03/30/2007
From:	Doerflein L Engineering Region 1 Branch 2
To:	Dacimo F Entergy Nuclear Operations
References
FOIA/PA-2011-0258 IR-07-007
Download: ML070890270 (63)

Text

March 30, 2007Mr. Fred R. DacimoSite Vice PresidentEntergy Nuclear Operations, Inc.Indian Point Energy Center450 Broadway, GSBP.O. Box 249Buchanan, NY 10511-0249SUBJECT:INDIAN POINT NUCLEAR GENERATING UNIT 2 - NRC COMPONENT DESIGNBASES INSPECTION REPORT 05000247/2007007

Dear Mr. Dacimo:

On February 15, 2007, the U.S. Nuclear Regulatory Commission (NRC) completed aninspection at Indian Point Nuclear Generating Unit 2. The enclosed inspection reportdocuments the inspection results, which were discussed on February 15, 2007, with Messrs. J. Ventosa and J. Comiotes and other members of your staff.The inspection examined activities conducted under your license as they relate to safety andcompliance with the Commission's rules and regulations and with the conditions of your license. This particular inspection was performed by a team of NRC inspectors and contractors usingNRC Inspection Procedure 71111.21, "Component Design Bases Inspection." In conducting theinspection, the team examined the adequacy of selected components and operator actions tomitigate postulated transients, initiating events, and design basis accidents. The inspection alsoreviewed Entergy's response to selected operating experience issues. The inspection involvedfield walkdowns, examination of selected procedures, calculations and records, and interviewswith station personnel. This report documents eight NRC-identified findings that were of very low safety significance(Green). Seven of these findings were determined to involve violations of NRC requirements. However, because of the very low safety significance of the violations and because they wereentered into your corrective action program, the NRC is treating the violations as non-citedviolations (NCV) consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contestany NCV in this report, you should provide a response within 30 days of the date of thisinspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission,ATTN: Document Control Desk, Washington, D.C. 20555-0001; with copies to the RegionalAdministrator, Region I; the Director, Office of Enforcement, U.S. Nuclear RegulatoryCommission, Washington, D.C. 20555-0001; and the NRC Resident Inspectors at Indian PointUnit 2.

F. Dacimo2In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, itsenclosure, and your response (if any) will be available electronically for public ins pection in theNRC Public Document Room or from the Publicly Available Records component of NRC'sdocument system (ADAMS). ADAMS is accessible from the NRC Web site athttp://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Lawrence T. Doerflein, ChiefEngineering Branch 2Division of Reactor SafetyDocket No. 50-247License No. DPR-26Enclosure:Inspection Report 05000247/2007007 cc w/encl:G. J. Taylor, Chief Executive Officer, Entergy Operations M. Kansler, President, Entergy Nuclear Operations, Inc.J. T. Herron, Senior Vice President for OperationsM. Balduzzi, Senior Vice President, Northeastern Regional OperationsW. Campbell, Senior Vice President of Engineering and Technical ServicesC. Schwarz, Vice President, Operations Support (ENO)K. Polson, General Manager OperationsO. Limpias, Vice President, Engineering (ENO)J. McCann, Director, Licensing (ENO)C. D. Faison, Manager, Licensing (ENO)R. Patch, Director of Oversight (ENO)J. Comiotes, Director, Nuclear Safety Assurance P. Conroy, Manager, LicensingT. C. McCullough, Assistant General Counsel, Entergy Nuclear Operations, Inc.P. R. Smith, President, New York State Energy, Research and Development AuthorityP. Eddy, Electric Division, New York State Department of Public ServiceC. Donaldson, Esquire, Assistant Attorney General, New York Department of LawD. O'Neill, Mayor, Village of BuchananJ. G. Testa, Mayor, City of PeekskillR. Albanese, Four County CoordinatorS. Lousteau, Treasury Department, Entergy Services, Inc.Chairman, Standing Committee on Energy, NYS AssemblyChairman, Standing Committee on Environmental Conservation, NYS AssemblyChairman, Committee on Corporations, Authorities, and CommissionsM. Slobodien, Director, Emergency PlanningB. Brandenburg, Assistant General CounselAssemblywoman Sandra Galef, NYS AssemblyCounty Clerk, Westchester County LegislatureA. Spano, Westchester County Executive

SUMMARY

During the period from January 8 through February 15, 2007, the U.S. Nuclear RegulatoryCommission (NRC) conducted a team inspection at the Indian Point Nuclear Generating Unit 2(IP 2) in accordance Inspection Procedure 71111.21, "Component Design Bases Inspection." The inspection procedure is conducted biennially as part of the NRC's Reactor OversightProcess (ROP).

1 The objective of the inspection was to verify that the IP 2 design bases hadbeen correctly implemented for selected risk-significant components, and that operatingprocedures and operator actions were consistent with the design and licensing bases. This wasto ensure that the selected components were capable of performing their intended safetyfunctions and could support the proper operation of the associated systems. The inspectionteam consisted of seven inspectors, including a team leader and three inspectors from theNRC's Region I Office, and three contractors. The inspection involved four weeks of on-siteeffort.The team selected nineteen components for a detailed design review after completing adetailed selection process. In selecting samples for review, the team focused on thosecomponents and operator actions that have a high relative contribution to the risk of apostulated core damage accident if the component was to fail or if the operator did notsuccessfully complete the action. The team also assessed available margin for the risk-significant components in selecting the samples. The selected samples included components inthe safety injection (SI), residual heat removal (RHR), auxiliary feedwater (AFW), onsiteelectrical power, and off-site electrical power systems. The team selected five risk-significantoperator actions for review using the complexity of the action, time to complete the action, andextent of training on the action as inputs. The team also selected six operating experienceissues related to the selected components or generic issues to verify they had beenappropriately assessed and dispositioned. For each sample selected, the team revieweddesign calculations, corrective action reports, maintenance and modification histories, andassociated operating and testing procedures. The team also performed walkdowns of theaccessible components to assess their material condition. Overall, the inspection team determined that the components reviewed were capable ofperforming their intended safety functions. The team also found that the operating procedures,operator training and equipment staging adequately supported completion of the operatoractions and were consistent with the design and licensing bases. The team did identify eightfindings of very low safety significance (Green) and one unresolved item. The eight findings arelisted in the "Summary of Findings" section of this report. The team assessed the safetysignificance of each of the findings using the NRC's Significance Determination Process (SDP).

2 Also, for each of the findings where current operability was a relevant question, Entergycompleted an operability evaluation. In each case, Entergy determined the equipment wasoperable. The inspection team independently confirmed Entergy's conclusions. All of thefindings were entered into Entergy's corrective action program to ensure a more comprehensiveassessment of the issue and to identify and implement appropriate corrective actions.

3 As described in Inspection Manual Chapter 0305, Operating Reactor AssessmentProgramEnclosure v Under the NRC's Reactor Oversight Process, findings of very low safety significance (Green)are addressed through the facility's correctiv e action program. Futu re NRC inspections, mostnotably the biennial Problem Identification and Resolution (PI&R) team Inspection, review asubstantial sample of Entergy's response to the Green findings and assess the adequacy of theactions taken to correct the deficiencies.The findings are also an input into the NRC's assessment process.

3 The most recentassessment of IP 2 issued on March 2, 2007 (ADAMS Ref. ML070610603), concluded that theplant's performance was in the Licensee Response Column of the NRC's Action Matrix. Because the findings of this Component Design Bases Inspection were all Green, the NRC'soverall assessment of IP 2 will not change from the Licensee Response Co lumn as a result ofthis inspection. The recent assessment also identified a substantive cross-cutting issue in thearea of human performance regarding procedure adequacy. The Reactor Oversight Processconsiders that the areas of human performance, problem identification and resolution and safetyconscious work environment, contain performance attributes that extend across (cross-cut) allareas of reactor plant operation. As noted in the inspection report, several of the findings hadcross-cutting aspects. As part of the assessment process, the NRC performs a collectivereview semi-annually of cross-cutting aspects of all inspection results from the previous twelvemonths, and monitors and evaluates a plant licensee's actions to address a substantive cross-cutting issue. This inspection is a key part of NRC's inspection effort to assure overall plant safety, protectionof the public and the environment, and efficacy of key plant design features and procedures. Many other NRC inspection and review activities are also important to NRC's role of ensuringsafety. More detail is provided in the NRC's description of the Reactor Oversight Process athttp://www.nrc.gov/NRR/OVERSIGHT/ASSESS/index.html. A similar inspection is planned forthe Indian Point Nuclear Generating Unit 3 in the Fall of 2007.

viSUMMARY OF FINDINGSIR 05000247/2007007; 1/8/2007 - 2/15/2007; Indian Point Nuclear Generating Unit 2;Component Design Bases Inspection.This inspection covers the Component Design Bases Inspection, conducted by a team of fourNRC inspectors and three NRC contractors. Eight findings of very low safety significance(Green) were identified, seven of which involved a violation of regulatory requirements and areconsidered to be non-cited violations. The significance of most findings is indicated by theircolor (Green, White, Yellow, Red) using IMC 0609, "Significance Determination Process" (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level afterNRC management review. The NRC's program for overseeing the safe operation ofcommercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process,"Revision 3, dated July 2000.A.

Cornerstone: Mitigating Systems

Green.

The team identified a finding of very low significance involving a non-citedviolation of 10 CFR 50, Appendix B, Cr iterion III, "Design Control," in that, Entergy didnot ensure adequate suction submergence for the three safety injection (SI) pumps bynot properly translating vortex and net positive suction head (NPSH) design parametersinto calculations relative to reactor water storage tank (RWST) level. Specifically,Entergy used a non-conservative method to calculate the level required to prevent pumpvortexing, and used a non-conservative RWST level value for determining availableNPSH for the SI pumps. Entergy entered the issue into their corrective action programand revised the affected calculations.The finding is more than minor because the calculation deficiencies represented reasonable doubt on the operability of the SI pumps, even though the pumps wereultimately shown to be operable. The finding is associated with the design controlattribute of the Mitigating Systems cornerstone and affected the cornerstone objective ofensuring the availability, reliability, and capability of sy stems that res pond to initiatingevents to prevent undesirable consequences. The finding has very low safetysignificance, based on Phase 1 of the significance determination process (SDP),documented in NRC Inspection Manual Chapter 0609, Appendix A, "SignificanceDetermination of Reactor Inspection Findings for At-Power Situations," because it was adesign deficiency that did not result in a loss of SI system operability, based upon theteam's verification of Entergy's revised calculations. (Section 1R21.2.1.1)*Green. The team identified a finding of very low significance involving a non-citedviolation of 10 CFR 50, Appendix B, Cr iterion III, "Design Control," in that, Entergy didnot accurately incorporate design parameters into valve thrust calculations for motoroperated valve (MOV) 746 and MOV 747. Specifically, Entergy used an incorrect andnon-conservative differential pressure in the calculations for MOV 746 and MOV 747,which were developed to verify that the valves could develop sufficient thrust to openunder postulated design basis conditions. Additionally, an incorrect equation was usedin determining the reduction in motor torque due to degraded voltage conditions.

viiEntergy entered the issue into their corrective action program and revised the affectedcalculations using the correct information.The finding is more than minor because the calculation deficiencies represented reasonable doubt on the operability of MOV 746 and MOV 747. The finding isassociated with the design control attribute of the Mitigating Systems cornerstone andaffected the cornerstone objective of ensuring the availability, reliability, and capability ofsystems that respond to initiating events to prevent undesirable consequences. Thefinding has very low safety significance, based on Phase 1 of the SDP, because it was adesign deficiency that did not to result in a loss of MOV 746 and MOV 747 operability,based upon the team's verification of Entergy's revised calculations. (Section1R21.2.1.2.b1)*Green. The team identified a finding of very low safety significance involving a non-citedviolation of 10 CFR 50, Appendix B, Cr iterion III, "Design Control," in that, Entergy did not establish adequate desi gn control measures to ensure the availability of the turbinedriven auxiliary feedwater pump (TDAFWP)during a postulated loss-of-offsite power(LOOP) event. Under certain LOOP situations, the team determined that the TDAFWPsteam supply could be inadvertently isolated because of inadequate calculations andprocedures for limiting the AFWP room temperature rise. Specifically, a calculation todetermine the auxiliary feedwater pump (AFWP) room tem perature rise during a LOOPdid not include heat input from the TDAFWP. Further, actions that could limit the rise inAFWP room temperature and prevent the inadvertent isolation of the TDAFW pump(opening an AFWP room roll-up door or promptly restoring forced ventilation) were notincluded in procedures. Entergy entered this issue into their corrective action program,implemented immediate compensatory actions, and revised AFWP room temperaturerise calculations.The finding is more than minor because it is associated with the design control attributeof the Mitigating Systems cornerstone and affected the cornerstone objective of ensuringthe availability, reliability and capability of system s that respond to initiating events toprevent undesirable consequences. The finding has very low safety significance, basedon Phase 1 of the SDP, because it did not represent the loss of safety function of theTDAFWP (single train) for greater than its 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> technical specification allowed outagetime, based on the team's review and assessment of site ambient temperature data overthe last year. (Section 1R21.2.1.7.b)*Green. The team identified a finding of very low safety significance (Green) involving anon-cited violation of 10 CFR 50.65(a)(1), the Maintenance Rule, in that, Entergy failedto monitor the gas turbine (GT) system in a manner that provided reasonable assurancethat the system could perform its intended safety function. Specifically, Entergy did not establish appropriate GT reliability goals, and therefore did not take corrective actions,when GT-1 had exceeded these goals for maintenance preventable functions failures(MPFF). In addition, Entergy did not properly classify repeat MPFFs, which resulted in asimilar failure to take corrective actions as required. This resulted in additional GT-1 outof service time that would not have happened if appropriate actions had been taken. Entergy entered this issue into their corrective action program and lowered the allowablegoal for MPFFs, and revised the GT-1 (a)(1) action plan to improve reliability.

viiiThe finding is more than minor because appropriate GT reliability goals were notestablished commensurate with safety and appropriate corrective actions were not takenwhen goals were not met. This finding is associated with the equipment performanceattribute of the Mitigating Systems cornerstone and affected the cornerstone objective ofensuring the availability, reliability and capability of syst ems that respond to initiatingevents to prevent undesirable consequences. The finding has very low safetysignificance, based on Phase 1 and Phase 2 of the SDP, which considered that theadditional GT-1 out of service time due to this issue could be as much as three days. The finding has a cross-cutting aspect in the area of human performance becauseEntergy did not adequately ensure procedures were complete, accurate, and up-to-date. Specifically, procedure ENN-DC-171, "Maintenance Rule Monitoring," did not providesteps to discriminate between the classification of an initial design deficiency and furtherfailures due to the same condition, resulting in mis-classifying several GT functionalfailures. (1R21.2.1.10.b1)*Green. The team identified a finding of very low safety significance involving Entergyprocedure, EN-LI-102, "Corrective Action Process," in that, Entergy failed to takecorrective actions to address degraded GT-1 reliability. This resulted in a two and onehalf day time period in January 2007 when GT-1 and GT-3 were simultaneouslyinoperable because, after GT-3 was made inoperable for planned maintenanceactivities, GT-1 was subsequently found to be inoperable. Specifically, the reliability ofGT-1 declined from an average of 75% for 2005 and the first 10 months of 2006, to 50%for the three months from November 2006 to January 2007; however, Entergy did not take actions to correct this degraded reliability. Entergy entered th is issue into theircorrective action program and developed an action plan to address GT reliability issues.The issue is more than minor because it is associated wi th the equipment reliabilityattribute of the Mitigating Systems cornerstone and affected the cornerstone objective ofensuring the availability, reliability, and capability of sy stems that res pond to initiatingevents to prevent undesirable consequences. The finding has very low safetysignificance, based on Phase 1 and Phase 2 of the SDP, assuming that both GT-1 andGT-3 were unavailable for the two and one half days, due to this issue. The finding hasa cross-cutting aspect in the area of problem identification and resolution becauseEntergy did not correct degraded reliability of GT-1, resulting in having GT-1 and GT-3simultaneously inoperable. (1R21.2.1.10.b2)*Green. The team identified a finding of very low safety significance (Green) involving anon-cited violation of Technical Specification 3.8.6.6, in that, Entergy did not performstation battery capacity testing in accordance with IEEE Standard 450-1995 (related tobattery maintenance and testing). Specifically, Entergy procedurally terminated batterycapacity testing at the rated discharge time (four hours), before reaching the minimumvoltage, as specified by IEEE Standard 450-1995. This prevented accurate quantitativemeasurement of capacity degradation and identification of the need to conduct potentialaccelerated battery testing, as specified by both IEEE Standard 450-1995 and thetechnical specifications, if battery capacity drops by more than 10% relative to theprevious test. Entergy entered the issue into their corrective action program andperformed calculations using past test data, which demonstrated that the capacities ofstation batteries had not degraded more than 10%.

ixThis issue is more than minor because it is associated with the procedure qualityattribute of the Mitigating Systems cornerstone and affected the cornerstone objective toensure the availability, reliability, and capability of system s that respond to initiatingevents to prevent undesirable consequences. The finding has very low safetysignificance, based on Phase 1 of the SDP, because it did not represent the loss ofstation battery safety function, based upon the team's verification of Entergy'scalculations. (Section 1R21.2.1.13.b1)*Green. The team identified a finding of very low safety significance involving a non-citedviolation of 10 CFR 50, Appendix B, Criterion XVI, "Corrective Action," in that, Entergydid not take effective corrective actions for a condition adverse to quality concerning out-of-tolerance inter-tier resistances on the No. 21 station battery. Specifically, afterrepeated failures of the No. 21 station battery inter-tier resistance testing, vendor andIEEE Standard 450-1995 recommended corrective actions were not taken to correct theadverse out-of-tolerance resistance trend. Entergy entered the issue into their correctiveaction program and performed calculations, which demonstrated that the voltage dropdue to the as-found resistance of the inter-tier connections was small and did not impactNo. 21 battery operability.This issue is more than minor because if it was left uncorrected, it would have become amore significant safety concern. Specifically, high resistance connections in a batterythat is loaded during accident conditions can cause localized heating and can causepermanent damage to the battery. The finding has very low safety significance, basedon Phase 1 of the SDP, because it did not represent the loss of No. 21 station batterysafety function, based upon the team's verification of Entergy's revised calculations. The finding has a cross-cutting aspect in the area of problem identification andresolution because Entergy did not take effective corrective actions to address theadverse trend of out-of-tolerance inter-tier resistances. (Section 1R21.2.1.13.b2)*Green. The team identified a finding of very low safety significance involving a non-citedviolation of 10 CFR 50, Appendix B, Criterion XVI, "Corrective Action," in that, Entergydid not promptly identify and correct a condition adverse to quality, with respect toknown errors in the No. 23 station battery design calculations. Specifically, Entergy didnot recognize at the appropriate time the need to write a condition report, perform anoperability determi nation, or pl ace controls on the use of the No. 23 battery designcalculations when errors were discovered in the No. 23 battery design calculations thatsignificantly lowered the battery capacity margin. Entergy entered the issue into theircorrective action program and performed calculations, which demonstrated No. 23station battery operability through the next refueling out age, based on t he calculatedmargin and conservatisms available.This issue is more than minor because it is associated with the design control attribute ofthe Mitigating Systems cornerstone and affected the cornerstone objective of ensuringthe availability, reliability, and capability of system s that respond to initiating events toprevent undesirable consequences. The finding has very low safety significance, basedon Phase 1 of the SDP, because it did not represent the loss of No. 23 station batterysafety function, based upon the team's verification of Entergy's revised calculations.

xThe finding has a cross-cutting aspect in the area of problem identification andresolution because Entergy failed to promptly identify the decrease in margin found inthe No. 23 battery design calculations of record. (Section 1R21.2.1.13.b3)B. Licensee-identified Violations None.

1RAW is the factor by which the plant's core damage frequency increases if thecomponent or operator action is assumed to fail.

2RRW is the factor by which the plant's core damage frequency decreases if thecomponent or operator action is assumed to be successful.Enclosure

REPORT DETAILS

1.REACTOR SAFETYCornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity1R21Component Design Bases Inspection (IP 71111.21).1Inspection Sample Selection ProcessThe team selected risk significant components and operator actions for review usinginformation contained in t he Indian Point 2 Probabilistic Risk Assessment (PRA) and theNuclear Regulatory Commission's (NRC) Standardized Plant Analysis Risk (SPAR)model. Additionally, the Indian Point 2 Significance Determination Process (SDP) Phase2 Notebook, Revision 2, was referenced in the selection of potential components andactions for review. In general, the selection process focused on components andoperator actions that had a risk achievement worth (RAW)1 factor greater than 2.0 or aRisk Reduction Worth (RRW)2 factor greater than 1.005. The components selectedwere located within both safety related and non-safety related systems, and included avariety of components such as pumps, valves, diesel generators, transformers, andelectrical buses.The team initially compiled an extensive list of components based on the risk factorspreviously mentioned. The team performed a margin assessment to narrow the focus ofthe inspection to 19 components and five operator actions. The team's evaluation ofpossible low design margin considered original design issues, margin reductions due tomodifications, or margin reductions identified as a result of material condition/equipmentreliability issues. The margin assessment evaluated the impact of licensing basischanges that could reduce safety analysis margins. The assessment also includeditems such as failed performance test results, corrective action history, repeated maintenance, maintenance rule (a)(1) status, operability reviews for degradedconditions, NRC resident inspector input of equipment problems, plant personnel input ofequipment issues, system health reports and industry operating experience. Consideration was also given to the uniqueness and complexity of the design and theavailable defense-in-depth margins. The margin review of operator actions includedcomplexity of the action, time to complete action and extent of training on the action.This inspection effort included walk-downs of selected components, a review of selectedsimulator scenarios, interviews with operators, system engineers and design engineers,and reviews of associated design documents and calculations to assess the adequacyof the components to meet both design bases and risk informed beyond design basisrequirements. A summary of the reviews performed for each component, operator 2Enclosureaction, operating experience sample, and the specific inspection findings identified arediscussed in the following sections of the report. Documents reviewed for this inspectionare listed in the attachment..2Results of Detailed Reviews.2.1 Detailed Component Design Reviews (19 Samples).2.1.1No. 21 Safety Injection Pump

a. Inspection Scope

The team reviewed design basis documents, including hydraulic calculations, technicalspecifications, accident analyses and drawings to ensure the No. 21 safety injection (SI)pump was capable of meeting system functional and design basis requirements. Because the water source for the pump during the injection phase of a postulatedaccident is the refueling water storage tank (RWST), the tank level setpoints anduncertainty calculations were reviewed. The team also reviewed SI pump test results,system health reports, and corrective action documents to verify SI pump designmargins were being maintained and to confirm that Entergy was entering problems thatcould affect system performance into the corrective action program. The team reviewedoperating and emergency procedures to verify adequate RWST inventory existed toinject water into the reactor during a postulated accident, and to ensure pump suctionswapover occurred before the onset of vortexing at the RWST inlet piping. To assessthe general condition of the pump, the team performed walkdowns of the SI pump area. The team also reviewed SI pump and motor cooler systems and SI pump minimum flow requirements to assess the ability of the SI pump to operate under design basisconditions.

b. Findings

Introduction:

The team identified a finding of very low significance (Green) involving anon-cited violation of 10 CFR 50, Appendix B, Criterion III, "Desi gn Control," in that, Entergy did not ensure adequate suction submergence for the three safety injection (SI)pumps by not properly translating vortex and net positive suction head (NPSH) designparameters into calculations relative to RWST level. Specifically, Entergy used a non-conservative method to calculate the reactor water storage tank (RWST) level requiredto prevent pump vortexing and used a non-conservative level value for determiningavailable NPSH for the SI pumps.

Description:

There are numerous methodologies available to calculate the minimumsubmergence level to prevent vortexing associated with pumps, primarily based oncorrelations of experimental data. The team noted that the methodology used incalculation FMX-00085, "Minimum Submergence Level SI/RHR and ContainmentSpray," Revision 0, to determine the minimum height of water above the SI pumps'intake to preclude vortex formation in the RWST was not appropriate. Specifically, theonset of vortexing was calculated using a methodology which was based upon fluid 3Enclosurewithdrawal from a tank at a constant level. The team questioned the validity andapplication of this approach, because the RWST is not maintained at a constant levelduring the postulated scenario, but rather, it would be pumped down and level woulddecrease.Based upon the above concern, Entergy acknowledged that the methodology used wasnot appropriate for determining the onset of vortexing in the RWST, and entered theissue into the corrective action program (CR-IP2-2007-00409 & CR-IP2-00439) toevaluate other calculational methods to ensure that the onset of vortexing would notoccur prior to suction swapover for the SI pumps (from the RWST to the containmentsump). The results of these other methods confirmed that the original methodology wasnon-conservative, resulting in reducing the available margin in RWST level from about 5inches to as low as 2.5 inches. The team determined that this design control deficiencydid not result in a loss of safety function of the SI pumps because there was stilladequate submergence to prevent vortexing at the suction inlet piping in the RWST.The team also reviewed Calculation FMX-00050-01, "SI Pump Available NPSH,"Revision 1. The team noted that the water level in the RWST corresponding to thebeginning of the pump suction swapover sequence was used in the calculation as theavailable static head of water (about 90 feet plant elevation). Since the SI pumps couldbe operating at a RWST water level corresponding to the level where operatorsterminate pump operation (about 82.5 feet), the calculation should have used 82.5 feetelevation when determining the static head of water. This resulted in reducing theavailable pump NPSH by about 7 feet. Entergy determined, and the team confirmed,that adequate NPSH remained for the SI pumps, but the margin over the required NPSHwas reduced. Entergy entered this issue in the corrective action program (CR-IP2-00712).Entergy's corrective actions for this issue included recalculating the SI pump vortex limitusing the appropriate methodologies, and they determined that there was not anoperability issue. With respect to SI pump NPSH, Entergy confirmed that the availableNPSH remained sufficient to prevent degraded pump performance and did not adverselyaffect pump operability. Further, Entergy plans to address the extent of c ondition as partof the condition report evaluations. The team reviewed Entergy's corrective actions andfound them to be appropriate.Analysis: The team determined that Entergy's failure to ensure adequate suctionsubmergence for the three SI pumps by not properly translating vortex and NPSH designparameters into calculations relative to RWST level was a performance deficiency thatwas reasonably within Entergy's ability to foresee and prevent. Specifically, Entergyused a non-conservative method to calculate the level required to prevent pumpvortexing and used a non-conservative RWST level value for determining availableNPSH for the SI pumps.The finding was more than minor because it was similar to NRC Inspection ManualChapter 0612, Appendix E, "Examples of Minor Issues," Example 3.j, in that, calculationdeficiencies repres ented reasonable doubt on the operability of the SI pumps. The 4Enclosurefinding was associated with the design control attribute of the Mitigating Systemscornerstone and affect ed the cornerstone objective of ensuring the availability, reliability,and capability of system s that respond to initiating events to prev ent undesirableconsequences. In particular, the formation of vortexing at the intake of the SI suctionline could result in air entrainment, which could cause pulsating pump flow and/ordegradation in pump performance; and inadequate pump NPSH available could result inpump cavitation and reduced flow. Traditional enforcement does not apply because theissue did not have any actual safety consequences or potential for impacting the NRC'sregulatory function, and was not the result of any willful violation of NRC requirements. In accordance with NRC Inspection Manual Chapter 0609, Appendix A, "SignificanceDetermination of Reactor Inspection Findings for At-Power Situations," the teamconducted a Phase 1 SDP screening and determined the finding was of very low safetysignificance (Green) because it was a design deficiency that did not result in a loss of SIsystem operability, based upon the team's verification of Entergy's evaluation.Enforcement

10 CFR Part 50, Appendix B, Criterion III, "Desi gn Control," requires, inpart, that measures shall be established to ensure that the design basis for structures,systems, and components are correctly translated into specifications, drawings,procedures, and instructions. Contrary to this requirement, as of January 24, 2007,Entergy had not correctly translated design bases into specifications, drawings,procedures, and instructions when they used a non-conservative methodology forcalculating the onset of vortexing at the intake of the SI pump common suction line fromthe RWST, resulting in reducing the available margin in RWST level from about 5 inchesto as low as 2.5 inches. Additionally, Entergy did not translate the appropriate RWSTwater level when calculating the NPSH available to the SI pumps, resulting in reducingthe available pump NPSH by about 7 feet. Because this violation is of very lowsignificance and has been entered into Entergy's corrective action program (CR-IP2-2007-00409, CR-IP2-2007-00439, and CR-IP2-2007-00712), this violation is beingtreated as a non-cited violation, consistent with Section VI.A.1 of the NRC EnforcementPolicy. (NCV 05000247/2007007-01, Inadequate Design Control Associated withVortexing and Net Positive Suction Head Calculations).2.1.2No. 21 Residual Heat Removal Heat Exchanger Discharge Valve (MOV 747)

a. Inspection Scope

The team selected residual heat removal (RHR) heat exchanger discharge motoroperated valve (MOV) 747 as a representative high risk valve sample. The teamreviewed calculations, procedures, periodic verification test results and technical reportsto verify the valve's capability to perfo rm during postulated design basis accidentconditions. The team also interviewed engineers and reviewed correspondence related to NRC Generic Letter 96-05, "Periodic Verification of Design-Basis Capability of Safety-Related Motor-Operated Valves," to verify that Entergy was meeting its commitments forMOV periodic verification. Preventive maintenance requirements and corrective actionreports were reviewed in order to determine the performance and operational history ofthe valve.

b. Findings

1.Inadequate Differ ential Pressure Value Used to Ensure MOV CapabilityIntroduction: The team identified a finding of very low significance (Green) involving anon-cited violation of 10 CFR 50, Appendix B, Criterion III, "Desi gn Control," in that,Entergy did not accurately incorporate design parameters into valve thrust calculationsfor motor operated valve (MOV) 746 and MOV 747. Specifically, Entergy used anincorrect and non-conservative differential pressure in the calculations for MOV 746 andMOV 747, which were developed to verify that the valves could develop sufficient thrustto open under postulated design basis conditions. Additionally, an incorrect equationwas used in determining the reduction in motor torque due to degraded voltageconditions. The equation used was only valid for degraded voltages 70% or greater thannominal voltage; however, the assumed degraded voltage for MOV 746 and MOV 747was less than 70% of nominal voltage.Description: The team noted that calculation PGI-00059-02, "746 & 747 DifferentialPressure Calculation," revised the maximum differential pressure (to open) for MOV 747from 1818 pounds per square inch - differential (psid) to 1600 psid (revised on October24, 1997). The valve receives a signal to open upon the initiation of an accident signal,and the valve must overcome a differential pressure equivalent to the differencebetween reactor coolant system pressure and the refueling water storage tank headpressure (reverse to normal flow direction). The maximum differential pressure wasbased on a postulated large break loss-of-coolant accident (LOCA). However, the teamquestioned whether the worst case differential pressure would occur during a postulatedsmall break LOCA, with its associated slower decrease in reactor pressure. Subsequently, Entergy confirmed that a more limiting differential pressure of 1852 psidshould have been applied in the calculation and was consistent with the differentialpressure assumed for a small break LOCA. This deficiency also applied to MOV 746(the No. 22 RHR heat exchanger discharge valve). Direct substitution of the higherdifferential pressure into the calculation yielded a negative thrust margin. Therefore,Entergy performed a calculation for both MOV 746 and 747, using an as-tested dynamicstem coefficient, and showed that both valves still had sufficient thrust margin, andtherefore remained capable of performing their intended design basis function.The team also noted that the degraded voltage calculation for MOV 747 performed inMMS-00088, "Analysis of Thrust and Torque Limits for Motor Operated Valve 747," usedan equation that was valid for degraded voltages greater than or equal to 70% ofnominal voltage; however, the assumed degraded voltage for the valve was less than70% of nominal voltage. Again, this deficiency similarly applied to MOV 746. Entergyperformed a calculation using an appropriate methodology for determining actuator output torque, and determined that both valves still had suffi cient margin and remainedoperable.Entergy's corrective actions included performing calculations as discussed above and conducting associated operability assessments. The team reviewed the calculations forboth issues as well as Entergy's associated operability assessments, and found them to 6Enclosurebe adequate. The team confirmed that the collective impact of the two deficiencies didnot adversely impact the operability of the valves.Analysis: The team determined that Entergy's failure to accurately incorporate designparameters into calculations for MOV 746 and MOV 747 was a performance deficiencythat was reasonably within Entergy's ability to foresee and prevent. Specifically, Entergyused an incorrect and non-conservative differential pressure in the calculations for MOV746 and MOV 747, which were developed to verify that the valves could developsufficient thrust to open under postulated design basis conditions. Additionally, anincorrect equation was used in determining the reduction in motor torque due todegraded voltage conditions. The equation used was only valid for degraded voltages70% or greater than nominal voltage; however, the assumed degraded voltage for MOV746 and MOV 747 was less than 70% of nominal voltage.The finding was more than minor because it was similar to NRC Inspection ManualChapter 0612, Appendix E, "Examples of Minor Issues," Example 3.j, in that, calculationdeficiencies repres ented reasonable doubt on the operability of MOV 746 and MOV 747. The finding was associated with the design control attribute of the Mitigating Systemscornerstone and affect ed the cornerstone objective of ensuring the availability, reliability,and capability of system s that respond to initiating events to prev ent undesirableconsequences. Traditional enforcement does not apply because the issue did not haveany actual safety consequences or potential for impacting the NRC's regulatory function,and was not the result of any willful violation of NRC requirements. In accordance withNRC Inspection Manual Chapter 0609, Appendix A, "Significance Determination ofReactor Inspection Findings for At-Power Situations," the team conducted a Phase 1SDP screening and determined the finding was of very low safety significance (Green)because it was a design deficiency that was confirmed not to result in a loss of MOV 746and MOV 747 operability, based upon the team's verification of Entergy's revisedcalculations.Enforcement: 10 CFR 50 Appendix B, Cr iterion III, "Design Contro l," requires, in part,that measures shall be established to ensure that the design basis for structures,systems, and components are correctly translated into specifications, drawings,procedures, and instructions. Contrary to the above, as of October 24, 1997, Entergydid not ensure that the design basis differential pressure for MOV 746 and MOV 747was correctly translated into the appropriate valve calculations, when calculation PGI-00059 was revised to include an incorrect and non-conservative differential pressure. Additionally, Entergy did not ensure that an appropriate equation was used indetermining the reduction in motor torque due to degraded voltage conditions for MOV746 and MOV 747. Because this violation is of very low safety significance and hasbeen entered into Entergy's corrective action program (CR-IP2-2007-00463), thisviolation is being treated as a non-cited violation consistent with Section VI.A.1. of theNRC Enforcement Policy. (NCV 05000247/2007007-02, Inadequate DifferentialPressure Value Used for MOV 746 and MOV 747 to Ensure Valve Capability)2.Use of Motor Control Center Methodology for MOV Periodic VerificationThe team identified an unresolved item (URI) concerning the adequacy of the motorcontrol center (MCC) testing methodology used for periodic verification of the designbases capability of safety-related MOVs. Entergy implemented MCC testing in 2004 asa method of implementing periodic verification in addition to the previously NRC-reviewed method of taking stem thrust and torque measurements at the valve. TheMCC method uses motor current, voltage, and winding resistance measured at the MCCto calculate motor torque of the valve's motor operator. The calculated motor torque isthen compared to motor torque target and limit values based on 1) packing loads, 2)thrust required to close the valve, 3) stall motor torque, and 4) valve or actuatorstructural limits. Entergy Report IP-RPT-04-00890, "Technical Basis for Using MCCTechnology for Periodic Verification Testing at IP 2 and IP 3," states that thismethodology would be used initially on MOVs with generally low safety significance andhigh operating margin, but also states that the report applies to all safety related MOVsat IP 2 and IP 3. Since 2004, Entergy has used the MCC methodology for periodicverification on nine safety-related MOVs: three high risk, three medium risk, and threelow risk MOVs, where risk significance is defined as the combined effects of MOV risk offailure and safety significance.Based on the available information, the team was unable to verify that the MCC methodhad been appropriately validated. Specifically, there did not appear to be a justifiedcorrelation between the MCC methodology calculated motor torque and actual stemthrust and torque. It was also unclear whether the MCC methodology had adequateallowances to compensate for its uncertainties in establishing MOV design basiscapability (such as uncertainties related to stem friction coefficient, load sensitivebehavior, and actuator efficiency) since stem thrust and stem torque are not directlymeasured. MCC testing was performed in 2004 as a periodic verification test on MOV 747, the No.21 RHR heat exchanger discharge valve, a high risk valve. The team identified that thistest was invalid because this was not performed in accordance with IP-RPT-04-00890. Specifically, MOV 747 was tested using the Motor Torque Method of MCC testing which,according to IP-RPT-04-00890, is only valid for motors whose torque is between 2 and60 foot-pounds. The motor on MOV 747 is an 80 foot-pound. motor and use of theCorrelated Thrust/Torque Method was required. As a result, Entergy exceeded the six-year periodic verification test interval for MOV 747 because the last "at the valve" validperformance verification test was performed in May 2000. Entergy has providedjustification for t he reasonable continued operability of the valve until its scheduledtesting in 2008 based on successful in-service tests, stem lubrication and actuatorpreventive maintenance and inspection performed in 2006. The team reviewedEntergy's basis for the operability of MOV 747 and determined that there wasreasonable assurance of continued operability of the MOV. Entergy committed to follow the Joint Owners' Group program for periodic verification ofMOVs in their response to NRC Generic Letter 96-05. This periodic verification program 8Enclosureestablished valve margin by measuring stem thrust and torque at the valve. Entergy'sresponse did not indicate that the MCC method would be used for MOV periodicverification.The MCC test method for periodic verification of MOVs is a departure from the NRC-reviewed method, which is based on direct measurement of stem thrust and torque. Theacceptability of the use of the MCC methodology for periodic verification of MOVs will bean unresolved item pending further NRC review. Included with this review will be adetermination of whether the MOV performance testing conducted on MOV 747constitutes a violation of NRC requirements. (URI 05000247/2007007-03, Use of MotorControl Center Methodology for Periodic Verification of the Design BasisCapability of Safety-Related MOVs).2.1.3Service Water Pumps and Strainers

a. Inspection Scope

The team selected the service water (SW) pumps and strainers to determine whetherthere was a potential for a common cause failure of the pumps and strainers. The teamreviewed design documents, including drawings, calculations, procedures, the SWdesign basis document, tests and modifications. The team reviewed these documentsto ensure the pumps and strainers were capable of meeting their design basisrequirements, with consideration of allowable pump degradation, net positive suctionhead requirements, and strainer clogging affects. To assess the current condition of thepumps, the team interviewed engineers, and reviewed system health and relatedcondition reports. To assess the general condition of the pumps and strainers, the teamperformed walkdowns of the SW pump house and strainer areas. Test results werereviewed to determine whether pump performance margins were sufficient to assuredesign basis assumptions could be achieved. Finally, SW system operating procedureswere reviewed to ensure the system was operated in accordance with its design basisrequirements.

b. Findings

No findings of significance were identified..2.1.4Pressurizer Power Operated Relief Valves (PCV-455C and PCV- 456)

a. Inspection Scope

The team reviewed instrument setpoint and uncertainty calculations for pressurizer level,temperature, and pressure instruments that were relied upon for overpressure protectionsystem operation. The team reviewed design calculations that were performed todetermine the lift settings of the power operated relief valves (PORV) while in the lowtemperature overpressure protection (LTOP) mode of operation and related proceduresto ensure the reactor coolant system (RCS) boundary is not compromised by violatingthe RCS pressure/temperature limits. The team also reviewed the adequacy of the 9Enclosurebackup nitrogen supply for the pressurizer PORVs, including sizing of the backup accumulator and pressure regul ating setpoints, to verify the capability to cycle eachPORV consistent with design basis assumptions.

b. Findings

No findings of significance were identified..2.1.5Safety Injection System Check Valve (SI 847)

a. Inspection Scope

The team selected the safety injection (SI) system check valve SI 847 as representativeof components whose failure posed very high risk for core damage. This valve is in thecommon suction line from the refueling water storage tank (RWST) for all three SIpumps. The team reviewed design drawings, vendor documents, calculations, conditionreports, test procedures and results, and interviewed engineers to confirm that the valvewas designed, maintained and operated in accordance with the design basisrequirements. The team verified that the check valve was opening when each SI pumpstarted, and verified, by reviewing test results, that the valve passed full flow in the opendirection. The team verified that the valve operation was periodically monitored by non-intrusive testing to ensure the valve would close to prevent back-leakage.

b. Findings

No findings of significance were identified..2.1.6No. 23 Emergency Diesel Generator (mechanical)

a. Inspection Scope

The team reviewed the No. 23 emergency diesel generator (EDG) to assess whether theEDG would function as required during postulated accident conditions to meet designbasis requirements. The review included the fuel oil storage and supply, starting air,ventilation and combustion air, and jacket water and lube oil cooling systems. The teamreviewed calculations, fuel oil transfer analyses, starting air capability analyses, heatexchanger performance analyses, system health reports, and selected condition reportsto verify maintenance, testing and operation of the EDG systems were successful inmeeting design basis requirements. Periodic test results and procedures were reviewedto verify fuel oil levels and transfer pump performance, starting air receiver pressures,and essential service flow rates were demonstrated and maintained within acceptablelimits. The team walked down selective accessible components and areas associatedwith the EDG to verify proper component alignment and the absence of observedadverse material conditi ons that could potentially impact system operability.

b. Findings

No findings of significance were identified.

.2.1.7 No. 21 Auxiliary Feedwater Pump

a. Inspection Scope

The team reviewed the No. 21 auxiliary feedwater (AFW) pump to verify the pump wascapable of achieving its design basis requirements. The review included an assessmentof the condensate storage tank, procedural guidance for transfer to the alternate sourceof water supply for the AFW system, pump vortex protection, available net positivesuction head, pump minimum flow and runout protection, and environmental andelectrical qualification of equipment. The team reviewed design documents, includingdrawings, calculations, procedures and tests to evaluate the functional requirements ofthe AFW pump. Test results were reviewed to confirm that appropriate test acceptancecriteria were established and that pump performance demonstrated that design basisaccident assumptions would be met. Additionally, the team reviewed system health andselected corrective action reports to assess the rigor and effectiveness of correctiveactions associated with Entergy's evaluation of design, maintenance, testing andoperational issues. The team performed a walkdown of accessible areas of the AFWand supporting systems to verify alignment was in accordance with design basis andprocedural requirements, and to assess the AFW system material condition.

b. Findings

Introduction:

The team identified a finding of very low safety significance (Green)involving a non-cited violation of 10 CFR 50, Appendix B, Crit erion III, "Design Control,"in that, Entergy did not establish adequate design control measures to ensure theavailability of the turbine driven auxiliary feedwater pump (TDAFW P) during a loss-of-offsite power (LOOP) event. Under certain LOOP situations, the team determined thatthe TDAFWP steam supply could be inadvertently isolated because of inadequatecalculations and procedures for limiting the AFWP room temperature rise. Specifically, a calculation to determine the auxiliary feedwater pump (AFWP) room te mperature riseduring a LOOP did not include heat input from the TDAFWP. Further, actions that couldlimit the rise in AFWP room temperature and prevent the inadvertent isolation of theTDAFW pump (opening an AFWP room roll-up door or promptly restoring forcedventilation) were not included in procedures.Description: The team reviewed calculation FCX-00086-00, "AFWP Room TemperatureRise," dated February 13, 1998. The team reviewed the calculation in part tounderstand the loss of ventilation effects on the TDAFWP during a LOOP. Thecalculation yielded relatively low temperature rises for the AFWP room, which containedtwo motor driven AFWPs and one TDAFWP. The highest resultant room temperaturewas 127.4 degrees Fahrenheit (F), assuming an outside air temperature of 100F. Theanalysis assumed the AFWP room roll-up door would be opened within 30 minutes ofthe onset of the LOOP. The automatic plant response to a LOOP would cause room 11Enclosureventilation, as well as other non-safety related loads, to be load shed from safety relatedelectric buses. The team noted that for a LOOP event, plant procedures did not directopening the AFWP roll-up door. The team also noted that the calculation did notappropriately consider heat input from the TDAFWP. Similar to the motor drivenAFWPs, the TDAFWP would automatically start at the onset of a LOOP event. Using the same calculation methodology, the team determined the AFWP roomtemperature would reach 202F with all three AFWPs operating and the roll-up doorclosed. Opening the roll-up door within 30 minutes of the onset of a LOOP results inadditional convection cooling, and room temperature would reach 139F with all threeAFWPs operating. However, the team considered the most limiting scenario to be thecombined operation of one motor driven AFWP and the TDAFWP (assuming the othermotor driven AFWP was not available or fails during the postulated event). If two motordriven AFWPs were operating, loss of the TDAFWP would be inconsequential as therewould be sufficient AFW flow to support design basis assumptions.The team noted that two temperature switches (TS) were installed at the ceiling of theAFWP room. The TSs sensed room air temperature and were designed to close the twosteam isolation valves to the TDAFWP. The steam isolation valves were in series, and asingle temperature switch closed the associated steam isolation valve at an establishedtemperature of 130F. The temperature switches were part of a design to isolate steamto the TDAFWP during a postulated high energy line break. The team noted that thesteam isolation valves were air-operated and backed with a normally aligned nitrogengas bottle such that the valves could close during LOOP conditions.The team reviewed several recent as-found calibration data for the two AFWP roomtemperature switches and noted one temperature switch was found to be set at 128Fon March 5, 2005. The TS was not recalibrated and 128F remained as the as-leftsetpoint. The team reviewed setpoint data for the installed temperature switches and noted that instrument repeatability was listed at 2.25F. The team concluded with 128F as anallowed and actual as-left setpoint, combined with an 2.25F instrument repeatabilityand other unanalyzed instru ment errors, reliability of the TDAFWP was not assured ifroom temperature was above 125.75F. Using the methodology of calculation FCX-00086-00, the team noted that an ambient air temperature of 93F would result in a bulkaverage AFWP room temperature of 126F with one motor driven AFWP and theTDAFWP running.In response, Entergy entered this issue into the corrective action program for furtherevaluation. For the near term, Entergy implemented a standing order, performed anoperability determi nation, and intended to proceduralize opening the roll up door orrestoring forced ventilation. The team reviewed these actions and found them to beappropriate.Analysis: The team determined that Entergy's failure to establish adequate designcontrol measures to ensure the availability of the TDAFWP during a LOOP event was a 12Enclosureperformance deficiency that was reasonably within Entergy's ability to foresee andprevent. Under certain LOOP situations, the team determined that the TDAFWP steamsupply could be inadvertently isolated because of inadequate calculations andprocedures for limiting the AFWP room temperature rise.

Specifically, a calculation todetermine the auxiliary feedwater pump (AFWP) room tem perature rise during a LOOPdid not include heat input from the TDAFWP. Further, actions that could limit the rise inAFWP room temperature and prevent the inadvertent isolation of the TDAFW pump(opening an AFWP room roll-up door or promptly restoring forced ventilation) were notincluded in procedures.This issue was more than minor because it was associated with the design controlattribute of the Mitigating Systems cornerstone and affected the cornerstone objective ofensuring the availability, reliability and capability of syst ems that respond to initiatingevents to prevent undesirable consequences. Traditional enforcement does not applybecause the issue did not have any actual safety consequences or potential forimpacting the NRC's regulatory function, and was not the result of any willful violation ofNRC requirements. In accordance with NRC Inspection Manual Chapter 0609,Appendix A, "Significance Determination of Reactor Inspection Findings for At-PowerSituations," the team conducted a Phase 1 SDP screening and determined the findingwas of very low safety significance (Green) because it did not represent the loss ofsafety function of the TDAFWP (single train) for greater than its 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> technicalspecification allowed outage time, based on the team's determination that over the lastyear, the site ambient temperature was not above 93F for more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Theteam reviewed site weather data for calendar year 2006, and noted that ambient airtemperature greater than 93F existed on five days, but based on the mean temperatureon those days, the temperature at the site was not above 93F for more than 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.Enforcement: 10 CFR 50 Appendix B, "Design Control," requires, in part, that measuresshall be established to assure that the design basis for structures, systems, andcomponents are correctly translated into procedures. Contrary to the above, as ofFebruary 13, 1998, calculation FCX-00086-00, "AFWP Temperature Rise," did notappropriately analyze environmental effects on the operability and availability of theTDAFWP, and actions to promptly open a roll-up door to the AFWP room were notincorporated into LOOP procedures. Because this violation is of very low safetysignificance and has been entered into Entergy's correction action program (CR-IP2-2007-00656, 00659, and 00662), this violation is being treated as a non-cited violation consistent with Section VI.A.1 of the NRC Enforcement Policy. (NCV05000247/2007007-04, Inadequate Design Control for Environmental Effects toEnsure the Availability of the Turbine Driven Auxiliary Feedwater Pump Operation)

.2.1.8 No. 23 Charging Pump

a. Inspection Scope

The team reviewed the No. 23 charging pump to verify its capability to meet design basisassumptions with respect to pump flow and pressure. The team reviewed calculations,drawings, procedures, tests, and other analyses to verify selected calculation inputs, 13Enclosureassumptions, and methodologies were accurate and justified, and were consistentlyapplied. The available net positive suction head for the charging pump and the coolingwater flow rates for the pump drive unit and frame lube oil coolers were verified to beconsistent with design assumptions to ensure reliable pump operation. The teamreviewed completed tests to confirm the acceptance criteria and test results demonstrated the capability of the pump to provide required flow rates. The teamreviewed system health and selective corrective action reports to assess theidentification and disposition of maintenance, testing, and operational issues. The teamalso conducted a walkdown of accessible components and features associated with the charging pump to verify the material condition of the pump and support systems featureswould not adversely affect system performance.

b. Findings

No findings of significance were identified..2.1.9Auxiliary Feedwater System Check Valves (BFD-31, -34, and -39)

a. Inspection Scope

The team inspected AFW system pump discharge check valves BFD-31, -34, and -39 toverify that each valve can open to pass the required design basis AFW system forwardflow and can close to prevent reverse flow. The inspection included a review of periodictest results, verification of the bases for flow acceptance criteria, and documentation ofdemonstration of closure to prevent reverse flow. The tests and criteria weredemonstrated in a combination of quarterly recirculation flow and refueling outage fullflow tests. The team reviewed non-intrusive and open-and-inspect test results to confirmsatisfactory check valve performance. The team also reviewed the corrective actionprogram, work control system database and system health reports to assess whetherthere were any adverse maintenance or performance trends with these valves.

b. Findings

No findings of significance were identified..2.1.10Gas Turbine No. 1

a. Inspection Scope

The team conducted interviews with engineers, conducted a walkdown of the equipment,and observed operation of gas turbine 1 (GT-1). The team also reviewed GT reliabilityand unavailability records, oper ator logs, condi tion reports, proc edures, completedsurveillances, modifications, the GT system reliability action plan, and maintenance rulebasis documents to verify the reliability and capability of GT-1 to provi de an alternatealternating current (AC) power source for station blackout and 10 CFR 50, Appendix Rfire scenarios. In particular, the team reviewed the capability of GT-1 to perform a "blackstart" without any AC power available. The team reviewed 20 volts direct current (Vdc)14Enclosureand 125Vdc battery sizing data and vendor data to evaluate the ability of the gas turbinesupport systems (black st art diesel, star ting diesel, and other auxiliaries) to perform theirfunctions without AC power available.

b. Findings

1.(Closed) URI 05000247/2006005-03: Reliability / Unavailability of the Gas TurbineSystem and Impact on FunctionalityIntroduction: The team identified a finding of very low safety significance (Green)involving a non-cited violation of 10 CFR 50.65(a)(1), the Maintenance Rule, in that,Entergy failed to monitor the GT system in a manner that provided reasonableassurance that the system could perform its intended safety function. Specifically,Entergy did not establish appropriate GT reliability goals, and therefore did not takecorrective actions, when GT-1 had exceeded these goals for maintenance preventablefunctions failures (MPFF). In addition, Entergy did not properly classify repeat MPFFsthat resulted in a similar failure to take corrective actions as required. This resulted inadditional GT-1 out of service time that would not have happened if appropriate actionshad been taken.Description: Gas turbines 1 and 3 (GT-1 and GT-3), are credited in Entergy's analysis tocope with station blackout and 10 CFR 50, Appendix R fire scenarios to ensure safeshutdown of the reactor. The system, consisting of GT-1, GT-3 and associated supportsystems, is classified as risk-significant in accordance with Entergy's Maintenance Ruleprogram. This system has been in a category (a)(1) monitoring status since theinception of the Maintenance Rule in 1996 due to the system's failure to achieve theestablished reliability goals, availability goals, or both during the last ten years. An (a)(1)action plan had been established to improve overall system performance.The team reviewed the applicable Maintenance Rule basis document and evaluated theestablished monitoring goals for availability and reliability. Specific to reliability, theestablished goal was less than or equal to five MPFFs and no repeat maintenancepreventable functional failures (RMPFFs) in a 24 month rolling cycle. The number ofallowable MPFFs was calculated under the assumption that there would be, on average,82 start demands during the 24 month cycle. The team reviewed the operating historyover the last three years and determined that the number of start demands averaged 38(per 24 month cycle). The review showed that the assumption for the number of startdemands was calculated based on data from a period when the GTs were routinely runto provide peaking power. Entergy stopped using the turbines for this purpose in 2000;however, they did not account for this change in operation from when the MaintenanceRule goal was evaluated and established. Based on this calculation methodology, theteam determined that the appropriate goal for MPFFs should be less than or equal totwo rather than five. GT-1 currently has three MPFFs over the last 24 month period, thelast of which occurred on August 6, 2006.The team also reviewed work orders and condition reports associated with the GTs forthe last two years. During this review, the team noted four failures of GT-1 due to low 15Enclosurecoolant level in the starting diesel heat exchanger. Entergy determined that the first ofthe four failures was due to a design deficiency associated with the GT-1 starting dieselcoolant system; and Entergy classified this failure as a MPFF. The three subsequentfailures were all classified as design deficiencies but none of them were similarlyclassified as MPFFs. The team reviewed the details associated with each failure andthe guidance in NUMARC 93-01, "Industry Guideline for Monitoring the Effectiveness ofMaintenance at Nuclear Power Plants," and determined that two of the remaining threefailures should have been classified as RMPFFs because they were due to the samedesign deficiency. The other failure involved additional failure mechanisms that wouldnot have resulted in a MPFF or RMPFF classification. As a result of the two failures thatshould have been RMPFFs, the established goal of no RMPFFs was exceeded (onAugust 6, 2006).The team determined that had the reliability goal been appropriate and justifiable, or thefunctional failures been appropriately classified, a review of the current (a)(1) action planand its associated corrective actions to improve system performance would have beenrequired. This would have resulted in additional corrective actions being performed toimprove system performance in order to meet the required reliability goal. This reviewwas not done, and no additional actions were implemented to improve GT availabilityand reliability. As a result, Entergy incurred an additional GT-1 RMPFF that could havebeen avoided had effective corrective actions been taken to meet reliability goals.Entergy entered this issue into their corrective action program. Entergy's short termcorrective actions included lowering the allowable goal for MPFFs to less than or equalto two; and revising the GT-1 (a)(1) action plan to improve reliability. The team foundthese corrective actions to be appropriate.Analysis: The team determined Entergy's failure to monitor the GT system in a mannerthat provided reasonable assurance that the system could perform its intended safetyfunction was a performance deficiency that was reasonably within Entergy's ability toforesee and prevent. Entergy did not establish appropriate GT reliability goals, andtherefore did not take corrective actions, when GT-1 had exceeded these goals forMPFFs. Specifically, Entergy did not update its reliability goals to reflect the reduction instart demands of the GTs and did not recognize that GT-1 had exceeded its allowedMPFFs. In addition, Entergy did not properly classify RMPFFs that resulted in a similarfailure to take corrective actions as required. Consequently, Entergy did not update theMaintenance Rule (a)(1) action plan to improve GT reliability and availability. Further,this resulted in additional GT-1 out of service time that would not have happened ifappropriate actions had been taken.The finding was more than minor because it was similar to NRC Inspection ManualChapter 0612, Appendix E, "Examples of Minor Issues," Example 7.a, in that,appropriate GT reliability goals were not commensurate with safety, and appropriatecorrective actions were not taken when goals were not met. This finding was associatedwith the equipment performance attribute of the Mitigating Systems cornerstone andaffected the cornerstone objective of ensuring the availability, reliability and capability of 16Enclosuresystems that respond to initiating events to prevent undesirable consequences. TheGTs are credited as an alternate AC power source for both station blackout and 10 CFR50, Appendix R fire scenarios. Traditional enforcement does not apply because theissue did not have any actual safety consequences or potential for impacting the NRC'sregulatory function, and was not the result of any willful violation of NRC requirements. In accordance with NRC Inspection Manual Chapter 0609, Appendix A, "SignificanceDetermination of Reactor Inspection Findings for At-Power Situations," the teamconducted a Phase 1 SDP screening and determined a more detailed Phase 2 SDPevaluation was required to assess the safety significance because the findingrepresented an actual loss of safety function of a non-Technical Specification requiredtrain of equipment designated as risk-significant per 10 CFR 50.65 for greater than 24hours. The team used the Risk-Informed Inspection Notebook for Indian Point NuclearGenerating Station Unit 2, to conduct the Phase 2 evaluation. Because of a lack ofdetail (only dates provided, not hours) in the data reviewed in condition reports and GToperating data, the team could not determine the exact number of additional hours thatGT-1 was unavailable over the one-year period ending September 30, 2006, related tothe two RMPFFs. However, by reviewing the associated dates in the data, the team wasable to approximate that the additional time was between two and three days. Accordingly, the team applied an initiating events likelihood of less than three days. ThePhase 2 approximation yielded a result of very low safety significance (Green). Themost dominant accident sequence involved a loss-of-offsite power, and the subsequentfailure of two emergency diesel generators in addition to the failure to restore powerwithin five hours via the off-site power network or one of the gas turbines [LOOP (4) +EAC (3) + REC5 (2) = 9].The finding has a cross-cutting aspect in the area of human performance becauseEntergy did not adequately ensure procedures were complete, accurate, and up-to-date. Specifically, procedure ENN-DC-171, "Maintenance Rule Monitoring," did not providesteps to discriminate between the classification of an initial design deficiency and furtherfailures due to the same condition, resulting in mis-classifying several GT functionalfailures.Enforcement: 10 CFR 50.65(a)(1) requires, in part, that holders of an operating licenseshall monitor the performance or condition of structures, systems, and components(SSC) within the scope of the rule as defined by 10 CFR 50.65(b), against licenseeestablished goals, in a manner sufficient to provide reasonable assurance that suchSSCs are capable of fulfilling their intended functions; and when the performance orcondition of a SCC does not meet established goals, appropriate corrective actions shallbe taken. Contrary to the above, as of August 6, 2006, Entergy failed to monitor thecondition of the GT system in a manner to provide reasonable assurance the systemcould perform its intended function. The established goals for reliability were notjustified and Entergy failed to properly evaluate RMPFFs. These errors resulted inEntergy not evaluating and taking appropriate corrective actions to improve systemperformance. Because this violation is of very low safety significance and has beenentered in Entergy's corrective action program (CR-IP2-2006-06842), this violation is 17Enclosurebeing treated as a non-cited violation consistent with Section VI.A.1 of the NRCEnforcement Policy. (NCV 05000247/2007007-05, Failure to Adequately Monitor GasTurbine System Performance as Required by the Maintenance Rule) 2.Failure to Correct Degraded Gas Tu rbine 1 ReliabilityIntroduction: The team identified a finding of very low safety significance (Green)involving Entergy procedure, EN-LI-102, "Corrective Action Process," in that, Entergyfailed to take corrective actions to address degraded GT-1 reliability. This resulted in atwo and one half day time period in January 2007 when GT-1 and GT-3 weresimultaneously inoperable because, after GT-3 was made inoperable for plannedmaintenance activities, GT-1 was subsequently found to be inoperable. Specifically, thereliability of GT-1 declined from an average of 75% for 2005 and the first 10 months of2006, to 50% for the three months from November 2006 to January 2007; however,Entergy did not take actions to correct this degraded reliability.Description: Gas turbines 1 and 3 (GT-1 and GT-3) are credited in Entergy's analysis tocope with station blackout and 10 CFR 50, Appendix R fire scenarios to ensure safeshutdown of the reactor. UFSAR Section 8.2.1.1, "Reliability Assurance," states that at least one gas turbine generator and associated switchgear and breakers shall beoperable at all times. If both GTs are inoperable, the UFSAR requires the system berestored to operable within seven days or a plant shutdown be performed.From January 2005 to about October 2006, GT-1 reliability, as measured by the ability of the gas turbine to start and load during surveillances, averaged 75%. However, duringthe months November 2006 to January 2007, GT-1 reliability declined to 50%. Inparticular, GT-1 failed each month's surveillance due to multiple automatic trips, and thesurveillance had to be re-performed on the following day. On two of the subsequentsuccessful surveillances, multiple starts were required to ultimately achieve asatisfactory surveillance result.After a successful surveillance of GT-1 on January 16, 2007, the NRC senior resident inspector questioned Entergy personnel whether the successful surveillance wassufficient to establish GT-1 operability given the recent poor GT-1 reliability. Inresponse, Entergy initiated condition report CR-IP2-2007-00259, and completed a Basisfor Functionality assessment in accordance with Proc edure EN-OP-104, "OperabilityDeterminations," which concluded that GT-1 was operable (functional). The assessmentrecommended that additional GT-1 testing should be conducted during the week ofJanuary 15 and additional dates (accelerated testing) in accordance with 2-SOP-31.1.2,"GT-1 Local Operations," to further establish GT-1 reliability. The Basis for Functionalityassessment's conclusion was based on the successful GT-1 surveillance on January 16,2007, as well as previously completed corrective actions. The team determined that thefunctionality assessment was inadequate because, although it recognized anddocumented an adverse GT-1 reliability trend, the large number of recent automaticshutdowns

(10) and equipment failures

(3) were not collectively evaluated andconsidered for overall GT system reliability and functionality. The team concluded that 18Enclosurehad Entergy performed an adequate analysis, they should have concluded that GT-1was not reliable, and therefore, non-functional.Following the GT-1 surveillance on January 16, at 12:14 p.m., a 13.8 kV bus section(13W94) was removed from service for switchyard maintenance. This action renderedGT-3 inoperable due to the unavailability of the associated switchgear and br eakers. OnJanuary 18, while the switchgear remained out-of-service, Entergy performed asurveillance on the GT-1 in accordance with the recommendations from Entergy's Basisfor Functionality document. The equipment failed the surveillance, resulting in GT-1being declared inoperable. Bus section 13W94 was returned to service on January 18at 11:45 p.m., thereby restoring GT-3 to an operable status. The team concluded thatboth GT-1 and GT-3 were unavailable during the time period January 16 - 18, 2007. Entergy entered this issue into their corrective action program, and developed an actionplan to address GT reliability issues. In addition, GT-1 remained out of service toinvestigate and repair the reliability challenges. The team reviewed Entergy's GTsystem action plan, and found it to be adequate.Analysis: The team determined Entergy's failure to take corrective actions to addressdegraded GT-1 reliability, in accordance with Entergy procedure, EN-LI-102, "CorrectiveAction Process," was a performance deficiency that was reasonably within Entergy'sability to foresee and prevent. The procedure stated that actions fo r a condition reportshould be determined, implemented and adequate to resolve the condition. AlthoughEntergy initiated a condition report and completed a functionality assessment, theassociated evaluation and corrective actions were not adequate. This resulted in a twoand one half day time period in January 2007 when GT-1 and GT-3 were simultaneouslyinoperable because, after GT-3 was made inoperable for planned maintenanceactivities, GT-1 was subsequently found to be inoperable. Specifically, the reliability ofGT-1 declined from an average of 75% for 2005 and the first 10 months of 2006, to 50%for the three months from November 2006 to January 2007; however, Entergy did not correct this degraded reliability.The issue was more than minor because it was associated wi th the equipment reliabilityattribute of the Mitigating Systems cornerstone and affected the cornerstone objective ofensuring the availability, reliability, and capability of sy stems that res pond to initiatingevents to prevent undesirable consequences. The GTs are credited as the alternate ACpower source for both station blackout and 10 CFR 50, Appendix R fire scenarios, asstated in UFSAR Section 8.2.1.1.In accordance with NRC Inspection Manual Chapter 0609, Appendix A, "SignificanceDetermination of Reactor Inspection Findings for At-Power Situations," the teamconducted a Phase 1 SDP screening and determined a more detailed Phase 2 SDPevaluation was required to assess the safety significance because the findingrepresented an actual loss of safety function of a non-Technical Specification requiredtrain of equipment designated as risk-significant per 10 CFR 50.65 for greater than 24hours (GT-1 and GT-3 were simultaneously unavailable for two and one half days fromJanuary 16 - 18, 2007). The team used the Risk-Informed Inspection Notebook forIndian Point Nuclear Generating Station Unit 2, to conduct the Phase 2 evaluation using 19Enclosurean initiating events likelihood of less than three days with an assumed inability to recoverAC power from the GTs in five hours (normal offsite power could still have beenrecovered). The most dominant accident sequence involved a station blackout (loss-of-offsite power with the failure of two emergency diesel generators) and failure to recoveroffsite power in five hours [LOOP (4) + EAC (3) + REC5 (1) = 8]. The Phase 2evaluation yielded a result of very low safety significance (Green).The finding has a cross-cutting aspect in the area of problem identification andresolution because Entergy did not correct the degraded reliability of GT-1, resulting inhaving GT-1 and GT-3 simultaneously inoperable.Enforcement: No violation of regulatory requirements occurred. The team determinedthat the finding did not represent a non-compliance because the gas turbine system isnot a safety related system. Entergy entered this issue in their corrective action program(CR-IP2-2007-00259 and CR-IP2-2007-00308), and developed a revised GT systemreliability action plan. (FIN 05000247/2007007-06, Failure to Correct Degraded GasTurbine 1 Reliability).2.1.11Residual Heat Removal Sump Isolation Valve (MOV 885A)

a. Inspection Scope

The team conducted interviews with engineers and reviewed calculations, procedures,periodic verification te st results, and technical reports to verify the capability of MOV885A to perform its intended function during postulated design basis accident conditions. NRC Generic Letter 96-05 (related to MOV periodic verification) correspondence wasreviewed to verify that Entergy was meeting its commitments for periodic verification ofthe valve. Preventive maintenance requirements and corrective action reports were alsoreviewed in order to determine the performance and operational history of the valve.

b. Findings

No findings of significance were identified..2.1.12Flooding in the 480Vac Switchgear Room

a. Inspection Scope

The team conducted a walkdown of the 480Vac switchgear room and reviewed the IP 2Individual Plant Examination of External Events, Probabilistic Safety Analysis FloodingAnalysis, drawings, and related evaluations to verify the conclusions made in theanalyses with respect to potential flooding scenarios were accurate and conservative. The team interviewed engineers and reviewed calculations, operating procedures, condition reports, and fire protection and service water inspection results to verify thatEntergy had taken steps to minimize the chance of flooding and had procedures in placeto minimize the consequences of flooding.

b. Findings

No findings of significance were identified..2.1.13Station Battery No. 21

a. Inspection Scope

The team reviewed the No. 21 battery design calculations to verify that the battery sizingwould satisfy the requirements of the safety related and risk significant DC loads, andthat the minimum possible voltage was taken into account. In particular, the evaluationfocused on verifying that the battery was adequately sized to supply the design dutycycle of the 125Vdc system for the loss-of-coolant accident/loss-of-offsite power(LOCA/LOOP) and Station Blackout loading scenarios, and that adequate voltage wouldremain available for the individual load devices required to operate during the scenariodurations. Plant drawings were reviewed to ensure that all loads were considered. TheNo. 21 battery charger sizing calculation was reviewed to evaluate whether it wasconsistent with the design and licensing bases. The team reviewed the DC protectivecoordination study to verify that breaker and fuse coordination was provided forpostulated faults in the DC system.In addition, a walkdown was performed to evaluate the condition of the battery andbattery charger. The team reviewed battery test procedures and results to determinewhether test acceptance criteria and frequency requirements specified in technicalspecifications and appropriate standards were satisfied. Engineers were interviewedregarding design aspects and operating history for the battery, and a sample of conditionreports was selected to verify that design and testing issues related to the No. 21 batterywere adequately addressed.

b. Findings

1.Inadequate Station Battery Capacity Testing for Degradation MonitoringIntroduction: The team identified a finding of very low safety significance (Green)involving a non-cited violation of Technical Specification 3.8.6.6, in that, Entergy did notperform station battery capacity testing in accordance with IEEE Standard 450-1995(related to battery maintenance and testing). Specifically, Entergy procedurallyterminated battery capacity testing at the rated discharge time (four hours), beforereaching the minimum voltage, as specified by IEEE Standard 450-1995. Thisprevented accurate quantitative measurement of capacity degradation and identificationof the need to conduct potential accelerated battery testing, as specified by both IEEEStandard 450-1995 and the technical specifications, if battery capacity drops by morethan 10% relative to the previous test.Description: The team reviewed the performance test results for battery No. 21 toensure adequate capacity was available and to verify that testing is performed inaccordance with IEEE Standard 450-1995 and the technical specifications.

21EnclosurePerformance testing is required every five years by Technical Specification 3.8.6.6 toverify adequate capacity and performance of the battery, but done every two years at IP 2.The team noted that according to step 7.2.4 of the performance test procedure, PT-R76A, "Station Battery 21 Load," the test duration is set to four hours. Since fourhours is the rated time for the discharge rate used, this typically terminates the test priorto reaching battery minimum voltage.The team found that Technical Specification 3.8.6.6 requires the capacity to be normallymeasured every 60 months, but the testing frequency is to be increased to every 12months when the battery shows degradation. According to the technical specificationsand IEEE Standard 450-1995, degradation is indicated when the battery capacity dropsby more than 10% relative to its capacity on the previous performance test. This is themeasured battery capacity at its minimum voltage (fully discharged), and compared withthe prior performance test.Battery capacity typically peaks between 110% and 115% and capacity is greater than100% for most of the life of the battery. By ending the capacity tests prior to reachingbattery minimum voltage, quantitative measurement of degradation is only possible if thebattery has had two tests below 100% capacity (the design basis is that they areoperable if over 80% capacity). Therefore, for most battery tests, Entergy has beenunable to quantitatively evaluate the technical specification testing frequency based onthe potential 10% degradation criteria that is measured at battery minimum voltage.Entergy subsequently analyzed the previous test results to calculate the capacitychanges for possible degradation in station batteries Nos. 22 and 24. Station batteryNo. 21 increased in capacity as is normal early in battery life, and station battery No. 23was below 100% capacity for two test cycles, so its capacity was directly measured (andno degradation was apparent). The largest calculated capacity decrease was 7% in twoyears for the No. 24 battery, which was less than the limit of 10%. However, providedthe calculated value was accurate and extrapolating the calculated results to a five yeartesting interval as is allowed by technical specifications, then the capacity coulddecrease significantly. The team found reasonable assurance of operability for thestation batteries after considering that the margin of error for the calculated values ofdegradation due to the non-linear characteristics of the battery discharge is large; thebattery capacities for batteries Nos. 22 and 24 were measured to be above 100% withan acceptance criteria of 80%; and the weekly, monthly and quarterly test results for thebatteries have been satisfactory. Entergy entered the issue into their corrective actionprogram (CR-IP2-2007-00193), and intended to appropriately revise the testingprocedures.Analysis: The team determined that Entergy's failure to perform station battery capacitytesting in accordance with IEEE Standard 450-1995 (related to battery maintenance andtesting), as required by Technical Specification 3.8.6.6, was a performance deficiencythat was reasonably within Entergy's ability to foresee and prevent. Specifically, Entergyprocedurally terminated battery capacity testing at the rated discharge time (four hours),

22Enclosurebefore reaching the minimum voltage, as specified by IEEE Standard 450-1995. Thisprevented accurate quantitative measurement of capacity degradation and identificationof the need to conduct potential accelerated battery testing, as specified by both IEEEStandard 450-1995 and the technical specifications, if battery capacity drops by morethan 10% relative to the previous test.This issue was more than minor because it was associated with the procedure qualityattribute of the Mitigating Systems cornerstone and affected the cornerstone objective ofensuring the availability, reliability, and capability of sy stems that res pond to initiatingevents to prevent undesirable consequences. Traditional enforcement does not applybecause the issue did not have any actual safety consequences or potential forimpacting the NRC's regulatory function, and was not the result of any willful violation ofNRC requirements. In accordance with NRC Inspection Manual Chapter 0609,Appendix A, "Significance Determination of Reactor Inspection Findings for At-PowerSituations," the team conducted a Phase 1 SDP screening and determined the findingwas of very low safety significance (Green) because it did not result in a loss of safetysystem function, based upon 1) the team's verification of Entergy's calculations, whichshowed less than 10% decrease in the station battery capacities, and 2) other batterytesting.Entergy determined that the battery test procedure was inadequate, and the 2003Improved Technical Specification project represented a missed opportunity to identifythe procedure error, although the procedure error apparently existed long before the2003 project. The team determined that because 1) the 2003 missed opportunity wasnot a significant contributor to the cause of the finding, and 2) the error was not reflectiveof current performance, there was not a cross-cutting aspect to this finding.Enforcement: Technical Specification 3.8.6.6 requires in part that battery capacitytesting be done at an increased frequency when the battery shows degradation. Thebasis for Technical Specification 3.8.6.6 states that, "degradation is indicated, accordingto IEEE Standard 450-1995, when the battery capacity drops by more than 10% relativeto its capacity on the previous performance test," and to "maintain the discharge rateuntil the battery terminal voltage decreases to a value equal to the minimum averagevoltage per cell . . . times the number of cells." Contrary to the above, as of January 12,2007, testing was terminated prior to reaching battery minimum voltage, whichprevented measuring the capacity quantitatively above 100%. Because this violation isof very low safety significance and has been entered into Entergy's corrective actionprogram (CR-IP2-2007-00193), this violation is being treated as a non-cited violationconsistent with Section VI.A.1 of the NRC Enforcement Policy. (NCV05000247/2007007-07, Inadequate Station Battery Capacity Testing forDegradation Monitoring) 2.Ineffective Corrective Action for High Inter-Tier Battery ResistancesIntroduction: The team identified a finding of very low safety significance (Green)involving a non-cited violation of 10 CFR 50, Appendix B, Criterion XVI, "Corrective 23EnclosureAction," in that, Entergy did not take effective corrective actions for out-of-tolerance inter-tier resistances on the No. 21 station battery. Specifically, after repeated failures ofthe station battery No. 21 inter-tier resistance testing, vendor and IEEE Standard 450-1995 recommended corrective actions were not taken to correct the adverse out-of-tolerance resistance trend.Description: The team reviewed past results from the annual performance test 2-PT-A035A, "21 Station Battery Inter-Cell Resistance Checks," to verify that inter-cell andinter-tier resistance checks were performed properly and any out-of-tolerancemeasurements were addressed.The team noted that various inter-tier connections had failed the resistance test for eachof the last four years. Of particular note was the inter-tier connection between cells 40and 41, which had failed all four years. The dominant concern for high resistanceconnections in the battery is that when loaded during accident conditions, they cancause localized heating that can cause melting of the connection or other permanentdamage to the battery. The corrective action for high resistance connections, based onboth IEEE Standard 450-1995 and the battery vendor manual, is to retorque theconnections and retest. If this does not correct the out-of-tolerance condition, then theconnection should be disconnected, cleaned, and remade.After the test failures (for high inter-tier resistance) in March 2004 and February 2005,actions were taken to address re-baselining affected connections due to a change in theresistance measurement instrument, but the out-of-tolerance connections were notretorqued or cleaned. In January 2006, the failed connections were retorqued. The out-of-tolerance inter-tier connections for the 2004, 2005, and January 2006 tests were onlyslightly greater than the acceptance criteria, but were generally trending higher. Whenthe most recent test was completed on December 4, 2006, two inter-tier connectionswere significantly out-of-tolerance, and the remaining inter-tier connections wereindeterminate since portions of the inter-tier cables had been removed without re-baselining the data. The acceptance criteria is 20% above baseline, and the worstconnection was approximately 43% above the baseline. A work order was written toretorque the connections; however, there was no retest or additional actions taken forthe connections.In response to this item, Entergy entered the issue into their corrective action program(CR-IP2-2007-00737) and issued a work order to retest the connections and takeappropriate actions based on the results. In addition, Entergy performed calculations,which demonstrated that the voltage drop due to the as-found resistance of the inter-tierconnections was small and did not impact No. 21 battery operability. The team verified that these calc ulations demonstr ated No. 21 station battery operability, and thatEntergy's completed and planned corrective actions were appropriate.Analysis: The team determined that Entergy's failure to take effective corrective actions for a condition adverse to quality concerning out-of-tolerance inter-tier resistances on theNo. 21 station battery was a performance deficiency that was reasonably within 24EnclosureEntergy's ability to foresee and prevent. Specifically, after repeated failures of the No. 21 station battery inter-tier resistance testing, vendor and IEEE Standard 450-1995 recommended corrective actions were not taken to correct the adverse out-of-toleranceresistance trend.This issue was more than minor because if it was left uncorrected, it would have becomea more significant safety concern. Specifically, high resistance connections in a batterythat is loaded during accident conditions can cause localized heating and can causemelting of the connection or other permanent damage to the battery. Traditionalenforcement does not apply because the issue did not have any actual safetyconsequences or potential for impacting the NRC's regulatory function, and was not theresult of any willful violation of NRC requirement s. In accordance with NRC InspectionManual Chapter 0609, Appendix A, "Significance Determination of Reactor InspectionFindings for At-Power Situations," the team conducted a Phase 1 SDP screening anddetermined the finding was of very low safety significance (Green) because it did notresult in a loss of safety system function, based upon the team's verification of Entergy'srevised calculations, which demonstrated that the voltage drop due to the as-foundresistance of the inter-tier connections was small and did not impact No. 21 batteryoperability.The finding has a cross-cutting aspect in the area of problem identification andresolution because Entergy did not implement timely and effective corrective actions toaddress an adverse trend of out-of-tolerance battery inter-tier resistances.Enforcement: 10 CFR 50 Appendix B, Criterion XVI, "Corrective Action," requires, inpart, that measures shall be established to assure that conditions adverse to quality arepromptly identified and corrected. Contrary to the above, between March 4, 2004, andFebruary 9, 2007, measures had not been established to ensure that therecommendations of the battery vendor and IEEE Standard 450-1995 were implementedwhen an adverse trend of out-of-tolerance battery inter-tier resistances were discoveredduring the last four annual resistance checks for No. 21 station battery. Because thisviolation is of very low safety significance and has been entered into Entergy's correctiveaction program (CR-IP2-2007-00737), this violation is being treated as a non-citedviolation consistent with Section VI.A.1 of the NRC Enforcement Policy. (NCV05000247/2007007-08, Ineffective Corrective Action for High Inter-Tier BatteryResistances)3.Untimely Corrective Actions for Decrease in Battery MarginIntroduction: The team identified a finding of very low safety significance (Green)involving a non-cited violation of 10 CFR 50, Appendix B, Criterion XVI, "CorrectiveAction," in that, Entergy did not promptly identify and correct a condition adverse toquality. Specifically, Entergy did not recognize at the appropriate time the need to write a condition report, perform an operability determi nation, or place controls on the use of the No. 23 battery design calculations when errors were discovered in the No. 23 batterydesign calculations that significantly lowered the battery capacity margin.

25EnclosureDescription: During a review of battery sizing and voltage drop calculations, the teamnoted several errors that reduced the capacity margin for various batteries. In an effortto show that these errors were previously identified and were being incorporated into thenewest revision of the calculations, the team was offered the draft revisions to thecalculations. The draft sizing (capacity) and voltage drop calculations were of generallyhigh quality. Entergy had recognized during the design review process of the new calculations thatsome loads were inadvertently omitted in the draft versions, such that correctionsneeded to be made prior to issuing the calculations. The effect of the new loads wouldbe to lower the final capacity margin. Although the margin generally appears to havedecreased for all station batteries, it was apparent that there will be sufficient margin forthe Nos. 21, 22, and 24 batteries when the calculations are complete. But, afterqualitatively considering the effects of the changes based on the approximate magnitudeof the loads to be added and the stated capacity margin in the new calculations, the team questioned the margin, and potentially the operability, of the No. 23 battery. Entergy's corrective actions included performing an operability review for this issue. Inparticular, Entergy perform ed a calculation, and acknowledged a potential operabilityconcern at low room temperatures (< 65F).

The team performed an independentcalculation, using Entergy's calculation inputs, data, and methodology. When correctedfor current battery age and typical minimum temperature, the result of the team'scalculation yielded about a negative 3% margin. In response, Entergy identified sixconservatisms in the draft calculation that can be refined to restore margin. The teamqualitatively reviewed the conservatisms and agreed that there was a reasonable basisfor current operability.Notwithstanding, the team performed independent calculations to consider futureoperability and found that without making any changes to the conservative assumptions,the design capacity (at the end of the life of the battery and at the lowest designtemperature) would be negative by 17%. The calculation of record (corrected for lowestdesign temperature) showed a positive capacity margin of 22%. Entergy had previous plans to replace the No. 23 battery in the next outage, which will prevent the decline in margin due to age degradation. The team found reasonable assurance of operabilitythrough the next outage (when the battery will be replaced), but it was unclear whetheroperability would have been assured for the design life of the battery. Entergy received the draft calculations from a contractor in April 2006, but due toformatting issues, did not receive the final draft copy until September 2006. Therefore,Entergy had from September 2006 until the team raised the issue in February 2007 touse the corrective action process to formally document and confirm operability andprevent the inaccurate calculations of record from being used without considering thenew information about decreased battery capacity. Because the new draft calculationsshowed a significant margin decrease that potentially affected current operability, andbecause the new draft calculations showed an even greater margin decrease at designconditions, it was not appropriate to delay initiating m easures to ensure operability, suchas writing a condition report, performing an operability determinat ion, or plac ing controls 26Enclosureon the use of the No. 23 battery sizing and voltage drop calculations of record. As aresult of the inspection, Entergy entered the issue into their corrective action program(CR-IP2-2007-00842).Analysis: The team determined that Entergy's failure to promptly identify and correct acondition adverse to quality, regarding known errors in the No. 23 station battery designcalculations, was a performance deficiency that was reasonably within Entergy's abilityto foresee and prevent. Specifically, actions were not taken to write a condition report,perform an operability deter mination, or pl ace controls on the use of the No. 23 batterydesign calculations when errors were discovered in the No. 23 battery designcalculations that significantly lowered the battery capacity margin.This issue was more than minor because it was associated with the design controlattribute of the Mitigating Systems cornerstone and affected the cornerstone objective ofensuring the availability, reliability, and capability of sy stems that res pond to initiatingevents to prevent undesirable consequences. Traditional enforcement does not applybecause the issue did not have any actual safety consequences or potential forimpacting the NRC's regulatory function, and was not the result of any willful violation ofNRC requirements. In accordance with NRC Inspection Manual Chapter 0609,Appendix A, "Significance Determination of Reactor Inspection Findings for At-PowerSituations," the team conducted a Phase 1 SDP screening and determined the findingwas of very low safety significance (Green) because it did not result in a loss of safetysystem function, based upon the team's verification of Entergy's revised calculations,which demonstrated operability through the next refueling outage.The finding has a cross-cutting aspect in the area of problem identification andresolution because Entergy failed to promptly identify the decrease in margin found inthe No. 23 battery design calculations of record.Enforcement: 10 CFR 50 Appendix B, Criterion XVI, "Corrective Action," requires, inpart, that measures shall be established to assure that conditions adverse to quality arepromptly identified and corrected. Contrary to the above, between September 2006 andFebruary 15, 2007, measures had not been established to ensure that the decrease indesign margin associated with the No. 23 battery was promptly identified and corrected. Because this violation is of very low safety significance and has been entered intoEntergy's corrective action program (CR-IP2-2007-00842), this violation is being treatedas a non-cited violation consistent with Section VI.A.1 of the NRC Enforcement Policy. (NCV 05000247/2007007-09, Untimely Corrective Actions for Decrease in BatteryMargin).2.1.14138kV Switchyard

a. Inspection Scope

The team reviewed the capability of the 138kV Switchyard to provide offsite power toIP 2. The team walked down the switchyard to observe the material condition of thegeneral area, breakers, switches, protective relaying equipment, battery backup power, 27Enclosureand power lines. The responsible engineers were interviewed regarding thecoordination between Entergy and ConEd for maintenance and operation of theswitchyard, the historical and recent maintenance issues with switchyard equipment,and upgrades to the switchyard. The Maintenance Rule basis document and associatedaction plan for the 138kV system were reviewed for completeness and effectiveness ofmanaging unavailability and unreliability of the switchyard. The system health reportwas reviewed to evaluate the managing of system challenges and future plans.Maintenance history was reviewed for indicating and protective equipment (lightningarresters, current transformers, and potential transformers) to verify that Entergy wasadequately testing and maintaining the equipment. Testing performance and vendorinformation were reviewed for the station auxiliary transform er and breaker BT4-5, whichare risk significant portions of the 138kV system, to verify that the equipment was beingtested and operated in accordance with the vendor guidance. A sample of conditionreports was selected to verify that issues related to the 138kV switchyard wereadequately addressed.

b. Findings

No findings of significance were identified..2.1.15Instrument Bus No. 23

a. Inspection Scope

The team reviewed the capability of the No. 23 instrument bus to provide in strumentationand control power during all conditions, but particularly during design basis accidentconditions. The calculation for loading and voltage drop was reviewed for the No. 23instrument bus to ensure that sufficient capacity exists for all normal and accidentloading, and that sufficient voltage was available for all loads. The No. 23 batteryloading study was reviewed to verify that the battery was capable of providing theappropriate load for the inverter. The team interviewed engineers to determine past andcurrent issues related to the system. The system health report was reviewed to evaluatethe management of system challenges. A sample of condition reports was selected toverify that issues related to the No. 23 instrument bus were adequately addressed.

b. Findings

No findings of significance were identified..2.1.16480Vac Switchgear - Bus 6A and Breaker 6A (Station Service Transformer Breaker)

a. Inspection Scope

The team reviewed condition reports and corrective and preventive maintenanceprocedures for Bus 6A and Breaker 6A to evaluate the reliability of equipment. Theteam reviewed the electrical distribution system load flow analysis and the calculation 28Enclosurethat evaluated the overload capability for the Westinghouse type DB-75 circuit breakerand 480Vac switchgear to determine the operating margin for components that wereidentified by calculation as limiting components during overload conditions. The teamconducted walkdowns of the switchgear to observe the material condition and operatingenvironment for indications of degradation of equipment. The team reviewed drawings,calculations, data sheets, and calibration tests to determine whether breaker 6Aovercurrent trip settings were appropriately selected and tested in accordance with theestablished acceptance criteria. The team also reviewed the degraded voltage relaysetpoint and uncertainty calculations, calibration test acceptance criteria, and relaycalibration test results to determine whether the degraded voltage relay settings were inaccordance with technical specification requirements.

b. Findings

No findings of significance were identified..2.1.17Emergency Diesel Generator Fuel Oil Transfer Pump Motor and Starter

a. Inspection Scope

The team reviewed fuel oil storage and transfer system design basis documents,including drawings, procedures, calculations and modifications to determine whether thepump, valve controls and alarm functions were in accordance with system design basisrequirements. The team reviewed condition reports, corrective and preventivemaintenance, and testing for the fuel oil transfer pump motors, motor starters, and fueloil day and storage tank level switches and alarms to determine the reliability ofequipment. The team reviewed the fuel oil transfer pump motor starter breaker andmotor feeder cable sizing, and the motors thermal overload protection to determinewhether the components were sized in accordance with design basis requirements. Theteam also conducted walkdowns of the components to assess the material condition andoperating environment of the equipment, and to determine that the installed componentsassociated with the No. 23 EDG fuel oil transfer pump motor starter were in accordancewith design analyses.

b. Findings

No findings of significance were identified..2.1.18Emergency Diesel Generator No. 23 (electrical), Starting Circuit, and Output Breaker

a. Inspection Scope

The team reviewed the EDG drawings and the schematics for the starting circuit, vendordata for the NST time delay relay and the diesel starting air motor solenoid, andcalculations to determine whether the selected components were maintained andoperated in accordance with the design bases. The team reviewed the EDG loadingstudy for the design basis loading conditions to determine the operating margin available 29Enclosureon the EDG and generator breaker ratings. The team conducted walkdowns of theEDGs and associated support equipment to determine the material condition andoperating environment for indications of degradation of equipment.

b. Findings

No findings of significance were identified..2.1.19RHR Heat Exchanger Discharge Valves MOV-746 and MOV-747 (Motors and Starters)

a. Inspection Scope

The team reviewed the one-line diagrams and schematics and the electrical distributionsystem load flow and valve motor circuit voltage analyses to determine the minimumvoltage available at the valve motor terminals during degraded voltage conditions. Theteam also reviewed the valve motor thermal overload sizing calculation to verify that theselected heater was considered in the minimum voltage analysis. The team reviewedthe valve operator thrust analysis to verify that the minimum voltage available wasconsidered when calculating the available thrust margin. The team also reviewedcondition reports and the corrective maintenance history for the valve motors and motor starters to determine the reliability of equipment.

b. Findings

No findings of significance were identified..2.2Detailed Operator Action Reviews (5 Samples)The team assessed manual operator actions and selected a sample of five operatoractions for detailed review based upon risk significance, time urgency, and factorsaffecting the likelihood of human error. The operator actions were selected from a PRAranking of operator action importance based on RAW and RRW values. The non-PRAconsiderations in the selection process included the following factors:*Margin between the time needed to complete the actions and the time availableprior to adverse reactor consequences;*Complexity of the actions;*Reliability and/or redundancy of components associated with the actions;*Extent of actions to be performed outside of the control room;*Procedural guidance; and*Training.

30Enclosure.2.2.1AC Power Recovery

a. Inspection Scope

The team selected complex operator actions to recover AC power to the safety relatedbuses via the alternate AC (AAC) power source (gas turbines 1 and 3). This actionshould be completed within one hour and potential consequence of failure of this actionis core damage after the station batteries deplete. The incorporation of this action intosite procedures, classroom training, and simulator training was reviewed. The team alsowalked down startup and transfer of the AAC power source to a safety related 480Vacbus with operators to verify that Entergy could restore AC power within the stationblackout coping duration. Finally, the team observed an operating crew respond to andimplement procedures for a station blackout scenario in the simulator.

b. Findings

No findings of significance were identified..2.2.2Align Backup Nitrogen Supply to Atmospheric Dump Valves

a. Inspection Scope

The team selected the operator action to locally align a backup nitrogen supply to the steam generator atmospheric dump valves (ADV). The time available to align backupnitrogen to the ADVs is critical and is based on the time at which reactor coolant systemcooldown is needed to mitigate a loss of reactor coolant pump seal cooling during astation blackout event. About 60 minutes is available to diagnosis the problem andcomplete the local operation. The team reviewed the incorporation of this action intoemergency and abnormal operating procedures, job performance measures, andtraining. The team observed an operator locate the local nitrogen supply valves andcontrols and walk through the actions to locally operate the ADVs.

b. Findings

No findings of significance were identified..2.2.3Manually Restart a Component Cooling Water Pump

a. Inspection Scope

The team selected the operator action to manually restart the component cooling water(CCW) pumps given an inadvertent trip signal. This action is time critical to prevent areactor coolant pump seal loss-of-coolant accident from occurring. The time available torestart a CCW pump is about 13 minutes. The team verified that central control roomannunciator response procedures provided instructions to reset CCW pump breakerlockout relays. The team also reviewed licensed operator training plans to verify thatoperators would understand the lockout device associated with CCW pump breaker 31Enclosureoperation. The team observed an operating crew respond to component cooling watermalfunctions in the simulator. Although the simulator scenario was not identical to thisoperator action, it was observed to verify that operators were alert to loss of CCWconcerns and were proficient with switch manipulations to restore CCW pumps.

b. Findings

No findings of significance were identified..2.2.4Align Alternate Safe Shutdown Equipment Following Switchgear Room Unavailability

a. Inspection Scope

The team selected the operator action to manually align the alternate safe shutdownsystems (ASSS) in the event the control room was rendered unavailable or normalcontrols and indications inoperable. Such conditions could exist for fire or floodingevents. Some ASSS alignments are time critical, about one hour, and the IP 2 NuclearPower Plant Probabilistic Safety Assessment, Appendix H, Human Reliability AnalysisNotebook, Revision 0, considered the operator actions as extremely high stress actions. The team observed an operator walk through the actions to align the No. 21 auxiliaryfeedwater pump, the No. 23 charging pump, and the No. 21 safety injection pump foralternate safe shutdown. The team verified that Entergy staged all necessary equipmentand tools in an appropriate location to expeditiously align the ASSSs. The incorporationof this action into site procedures, classroom training, and job performance measureswere also reviewed.

b. Findings

No findings of significance were identified..2.2.5Manually Control Turbine Driven Auxiliary Feedwater Pump Following Battery Depletion

a. Inspection Scope

The team selected the operator action to manually control the turbine-driven auxiliaryfeedwater pump (TDAFWP) following battery depletion. The potential consequence offailure of this action is core damage after steam generators overfill and damage theTDAFWP due to moisture carryover. This operator action involved controlling severalsteam and feedwater valves associated with the TDAFWP. The IP 2 Nuclear PowerPlant Probabilistic Safety Assessment, Appendix H, Human Reliability AnalysisNotebook, Revision 0, considered the operator actions as extremely high stress withmoderate complexity. The team observed an operator walk through the actions tolocally control steam generator levels as well as locally operating all steam controlvalves to the TDAFWP. The team verified that Entergy staged all necessary tools in anappropriate location to expeditiously operate the TDAFWP. The incorporation of thisaction into site procedures, classroom training, and job performance measures werealso reviewed.

b. Findings

No findings of significance were identified.

.3 Review of Industry Operating Experience (OE) and Generic Issues (6 Samples)

a. Inspection Scope

The team reviewed selected OE issues for applicability at Indian Point Unit 2. The teamperformed a detailed review of the OE issues listed below to verify that Entergy hadappropriately assessed potential applicability to site equipment and initiated correctiveactions when necessary..3.1NRC Information Notice (IN) 1991-51, Inadequate Fuse Control ProgramsThe team reviewed Entergy's disposition of IN 1991-51. This Information Noticeemphasized the importance of programs to control activities related to fuses. The teaminterviewed the IP 2 Fuse Control Program Coordinator to discuss the development ofthe program, implementation of the program, coordination between operations andengineering, current issues, and historical issues. The team reviewed the documentswhich implement the program to verify that fuses are controlled in accordance with thedirectives and procedures. A sample of condition reports was also reviewed to verifythat fuse related problems were identified and handled appropriately..3.2NRC IN 2005-023, Vibration-Induced Degradation of Butterfly ValvesThe team reviewed Entergy's evaluation of IN 2005-03 to assess the thoroughness andadequacy of the subject evaluation. IN 2005-03 focused on separation of butterfly valveinternal components due to the vibration-induced loss of taper pins used to connectthem. Entergy's evaluation included conducting a search of the corrective actiondatabase to identify whether there were condition reports involving related valve failures,and reviewing valve preventive maintenance procedures to evaluate the measuresemployed at IP 2 to secure the valve disc-to-stem taper pins. The results of Entergy'sevaluation indicated that the subject butterfly valves were not susceptible to vibration-induced failure as described in the Information Notice..3.3NRC IN 2006-03, Motor Starter Failures Due to Mechanical-Interlock BindingThe team reviewed Entergy's disposition of IN 2006-03, which addressed mechanical-interlock binding due to misalignment that resulted from a mounting hole offset in certainmotor starters. Although the subject starters were not used at IP 2, the motor starters inuse have also exhibited similar problems due to mechanical-interlock binding that wasdetermined by Entergy to be a result of age-related lubrication degradation. The teaminterviewed the system engineer responsible for implementing the corrective action toreplace the installed starters' mechanical-interlock mechanisms with a type of animproved design. The team confirmed that all potentially vulnerable starters have beenupdated with the improved design mechanism for the mechanical-interlock.

33Enclosure.3.4NRC IN 2006-29, Potential Common Cause Failure of Motor-Operated Valves as aResult of Stem Nut WearThe team conducted interviews with the MOV engineers and reviewed documents inorder to determine whether Entergy experienced stem nut wear issues and if appropriateaction had been taken as a result of the IN. The team determined that Entergylubricates their valve stems every two years, has not had any stem nut failures, andsends their stem nut to the valve manufacturer for machining. As a result of the IN,Entergy revised their diagnostic test procedure to evaluate stem nut wear..3.5NRC IN 2006-15, Vibration Induced Degradation and Failure of Safety-Related ValvesThe team reviewed Entergy's response and actions that addressed the applicability ofthe valve vibration issues identified in NRC IN 2006-15. The team verified that Entergyperformed a review of plant equipment databases and documents, which confirmed thatthe station was not vulnerable to the type of valve degradation described in theInformation Notice..3.6NRC IN 2005-11: Internal Flooding/Spray-Down of Safety-Related Equipment Due toUnsealed Equipment Hatch Floor Plugs and/or Blocked Floor DrainsThe team reviewed Entergy's disposition of IN 2005-11, whic h illustrated the potential fordegradation of multiple trains of emergency core cooling systems as a consequence ofpotential flooding in safety-related areas. The team verified that Entergy entered IN2005-11 into its corrective action program for review and considered all actions listedwithin the IN. Entergy actions completed included verifying that current plantconfiguration of flood protection features was consistent with the design basis andUFSAR descriptions, and establishing drain system periodic maintenance.

b. Findings

No findings of significance were identified.4.OTHER ACTIVITIES 4OA2Problem Identification and Resolution

a. Inspection Scope

The team reviewed a sample of problems that were identified by Entergy and enteredinto the corrective action program. The team reviewed these issues to verify anappropriate threshold for identifying issues, and to evaluate the effectiveness ofcorrective actions related to design or qualification issues. In addition, condition reports,written on issues identified during the inspection, were reviewed to verify adequateproblem identification and incorporation of the problem into the corrective actionprogram. The specific condition reports that were sampled and reviewed by the teamare listed in the attachment to this report.

b. Findings

No findings of significance were identified in addition to the corrective action deficienciesidentified separately in this inspection report.4AO6Meetings, Including ExitOn February 15, 2007, the team presented the inspection results to Mr. J. Ventosa,Director, Engineering, and Mr. J. Comiotes, Director, Nuclear Safety Assurance, andother members of Entergy staff. The team verified that no proprietary information isdocumented in the report.

A-1AttachmentATTACHMENT

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

R. Altadonna, Program and Components Engineer

E. Anderson, Design Engineer (Electrical)

V. Andreozzi, System Engineering Supervisor

J. Bencivenga, Design Engineer (Mechanical)

J. Bubniak, Design Engineer (Mechanical)

D. Carleton, Maintenance Supervisor

T. Chan, System Engineer

G. Dahl, Licensing Engineer

J. Etzweiler, Operations Coordinator

A. Galati, Design Engineer (Mechanical)

D. Gaynor, Senior Lead Engineer

J. Herrera, System Engineer

M. Imai, System Engineer

J. Kayani, Heat Exchanger Component Engineer

M. Kempski, System Engineer

E. Kenney, MOV Program Engineer

A. King, Design Engineer

C. Laverde, MOV Program Engineer

R. Lee, Design Engineer (Mechanical)

T. Moran, Check Valves Program Engineer

T. Orlando, Design Engineering Manager

J. Pineda, System Engineer

J. Raffaele, Design Engineering Supervisor

V. Rizzo, AOV Program Engineer

H. Robinson, Design Engineer (Electrical)

F. Weinert, Design Engineer (Electrical)

J. Whitney, System Engineer

S. Wilkie, Fire Protection Engineer

NRC Personnel

M. Cox, Senior Resident Inspector

B. Wittick, Resident Inspector

W. Schmidt, Senior Risk Analyst

A-2Attachment

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000247/2007007-03URIUse of Motor Control Center Methodology for PeriodicVerification of the Design Basis Capability of Safety-Related MOVs (Section 1R21.2.1.2.b2)

Closed

05000247/2006005-03URIReliability / Unavailability of the Gas Turbine System andImpact on Functionality (Section 1R21.2.1.10.b1)

Opened and Closed

05000247/2007007-01NCVInadequate Design Control Associated with Vortexing andNet Positive Suction Head Calculations (Section1R21.2.1.1b)05000247/2007007-02NCVInadequate Differential Pressure Value Used for MOV 746and MOV 747 to Ensure Valve Capability (Section1R21.2.1.2.b1)05000247/2007007-04NCVInadequate Design Control for Environmental Effects toEnsure the Availability of the Turbine Driven AuxiliaryFeedwater Pump Operation (Section 1R21.2.1.7b)05000247/2007007-05NCVFailure to Adequately Monitor Gas Turbine SystemPerformance as Required by the Maintenance Rule(Section 1R21.2.1.10.b1)05000247/2007007-06FINFailure to

Correct Degraded Gas Turbine 1 Reliability(Section 1R21.2.1.10.b2)05000247/2007007-07NCVInadequate Station Battery Capacity Testing forDegradation Monitoring (Section 1R21.2.1.13.b1)05000247/2007007-08NCVIneffective Corrective Action for High Inter-Tier BatteryResistances (Section 1R21.2.1.13.b2)05000247/2007007-09NCVUntimely Corrective Actions for Decrease in Battery Margin(Section 1R21.2.1.13.b3)

A-3Attachment

LIST OF DOCUMENTS REVIEWED

Calculations18.03.F02.007, Air Operated Gate/Globe Valve Component Calculations, Rev. 1CN-SEE-03-5, IP 2 RHR Cooldown Analysis for the 5% Power Uprate Program, Rev. 0DOE-2001-2958-FFX, Determination of Equivalency for GT1 Starting Diesel Battery, Rev. 0